SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2003

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period___________to______________

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification Number

1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation) 300 Erie Boulevard West Syracuse, New York 13202 315.474.1511

Securities registered pursuant to Section 12(b) of the Act:
(Each class is registered on the New York Stock Exchange)

Registrant	Title and Class

Niagara Mohawk Power Corporation	Preferred Stock ($100 par value-cumulative):

		3.90% Series
		3.60% Series

	Preferred Stock ($25 par value-cumulative):
	Adjustable Rate Series D

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [ X ] NO [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ X ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES [ ] NO [ X ]

State the aggregate market value of the common equity held by non-affiliates of the registrant: N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Registrant	Title	Shares Outstanding at June 24, 2003

Niagara Mohawk Power Corporation	Common Stock, $1.00 par value	187,364,863
	(all held by Niagara Mohawk Holdings, Inc.)

NIAGARA MOHAWK POWER CORPORATION

TABLE OF CONTENTS


PART I

Item 1.	Business
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders

PART II

Item 5.	Market for the Registrants’ Common Equity and Related Stockholders Matters
Item 6.	Selected Consolidated Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

PART III

Item 10.	Directors and Executive Officers of the Registrant
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management
Item 13.	Certain Relationships and Related Transactions
Item 14.	Controls and Procedures

PART IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K

Signatures

Certifications

FORWARD-LOOKING INFORMATION

This report and other presentations made by Niagara Mohawk Power Corporation (the “Company”) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes” or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

(a) the impact of further electric and gas industry restructuring;

(b) the impact of general economic changes in New York;

(c) federal and state regulatory developments and changes in law which may have a substantial adverse impact on revenues or on the value of the Company’s assets;

(d) federal regulatory developments concerning regional transmission organizations;

(e) changes in accounting rules and interpretations which may have an adverse impact on the Company’s statements of financial position and reported earnings;

(f) timing and adequacy of rate relief;

(g) adverse changes in electric load;

(h) climatic changes or unexpected changes in weather patterns; and

(i) failure to recover costs currently deferred under the provisions Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulations”, as amended, and the Merger Rate Plan in effect with the New York State Public Service Commission.

NIAGARA MOHAWK POWER CORPORATION

PART I

ITEM 1. BUSINESS

On January 31, 2002, Niagara Mohawk Holdings, Inc. (“Holdings”), parent company of Niagara Mohawk Power Corporation (the “Company”) became a wholly owned subsidiary of National Grid USA (“National Grid”). National Grid is a wholly owned subsidiary of National Grid Transco plc (“NGT”). NGT owns and operates the high voltage transmission system and natural gas distribution system in England and Wales. NGT, through National Grid, also has substantial transmission and distribution operations in the United States. The combination of the Company and National Grid more than doubled the size of NGT’s U.S. operations, with an electric customer base of approximately 3.3 million.

The Company was organized in 1937 under the laws of New York State and is engaged principally in the regulated energy delivery business in New York State. The Company provides electric service to approximately 1,500,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately 557,000 gas customers in areas of central, northern and eastern New York State.

In conjunction with the closing of the merger with National Grid a new rate plan (“Merger Rate Plan”) that had previously been approved by the PSC went into effect, superceding the Power Choice rate plan. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Business - Merger Rate Plan” for a detailed discussion of this rate plan.

For a discussion of events that occurred during 2003 and 2002, including the restructuring of the regulated electric utility business, other federal and state regulatory initiatives, and the Company’s efforts to address deregulation and its financial condition, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

REGULATION AND RATES

Several critical initiatives have been undertaken by various regulatory bodies and the Company that have had, and are likely to continue to have, a significant impact on the Company and the utility industry. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business” and “Other Federal and State Regulatory Initiatives,” for a discussion of these initiatives.

For a discussion of the Merger Rate Plan approved by the PSC in November 2001 and the three-year gas rate settlement agreement, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Regulatory Agreements and the Restructuring of the Regulated Electric Utility Business.”

ELECTRIC SUPPLY PLANNING

Although the Company has exited the generation business, the Company must still arrange for electric supply through a transition period and as provider of last resort, in that the Company will provide electricity and gas to its customers who are unable or unwilling to obtain an alternative supplier. Under the Power Choice agreement, the PSC approved the Company’s plan to divest its fossil and hydro generation assets, which was a key component in its Power Choice agreement to lower average electricity prices and provide customer choice. By November 2001, the Company completed the sale of the last of its generation assets, its nuclear assets, to a subsidiary of Constellation Energy Group, Inc. (“Constellation”). In connection with the generation asset sales, the Company has entered into various agreements to purchase its power needs from the buyers of the generation assets or entered into financial swaps with the buyers that hedge the price of electricity. The Company also entered into financial swaps with certain of the parties to the Master Restructuring Agreement (“MRA”). The MRA, which occurred in 1998, terminated, restated, or amended certain Independent Power Producer (“IPP”) Purchase Power Agreements (“PPAs”). The Company continues to purchase energy from various suppliers under long-term PPAs and purchases any additional power needs on the open market through the NYISO. The NYISO commenced operations in December 1999 as a result of a FERC ruling which promotes competition by requiring public utilities owning, operating, or controlling interstate transmission facilities to file tariffs which offer others the same transmission services they provide for themselves, under comparable terms and conditions. For a discussion of the results of the power contracts and several financial agreements to hedge the price of electricity, see Part II, Item 8. Financial Statements and Supplementary Data - Note I. Commitments and Contingencies, and Note J. Derivatives and Hedging Activities.

ELECTRIC DELIVERY PLANNING

As of March 31, 2003, the Company had approximately 52,000 pole miles of transmission and distribution lines for electric delivery. Evaluation of these facilities relative to NYISO, Northeast Power Coordinating Council, and North American Electric Reliability Organization, planning criteria, security considerations, and anticipated Company internal and external demands is an ongoing process intended to maintain the reliability of electric service while minimizing the capital requirements for expansion of these facilities. The Company continually reviews the adequacy of its electric delivery facilities and establishes capital requirements to support new load growth.

GAS SUPPLY

The majority of the Company’s gas sales are for residential and commercial space heating. Consequently, the demand for natural gas by the Company’s customers is seasonal and influenced by weather factors. The Company purchases its natural gas under firm supply agreements. The natural gas purchased may be either transported or stored for later transport on a firm basis through interstate storage facilities and pipelines to the Company's system.

GAS DELIVERY

The Company sells, distributes and transports natural gas to a geographic territory that generally extends from Syracuse to Albany. The northern reaches of the system extend to Watertown and Glens Falls. Not all of the Company’s distribution areas are physically interconnected with one another by its own facilities. Presently there are 12 separate distribution zones connected to 4 interstate natural gas pipelines regulated by the FERC. Niagara Mohawk has nineteen direct connections with Dominion Transmission, Inc., two with Iroquois Gas Transmission, one with Empire State Pipeline, and one with Tennessee Gas Pipeline.

ENVIRONMENTAL MATTERS

General. Niagara Mohawk’s operations and facilities are subject to numerous federal, state and local laws and regulations relating to the environment including, among other things, requirements concerning air emissions, water discharges, site remediation, hazardous materials handling, waste disposal and employee health and safety. While the Company devotes considerable resources to environmental compliance and promoting employee health and safety, the impact of future environmental health and safety laws and regulations on the Company cannot be predicted with certainty.

In compliance with environmental statutes and consistent with its strategic philosophy, the Company performs environmental investigations and analyses and installs, as required, pollution control equipment, including, among other things, effluent monitoring instrumentation and materials storage/handling facilities designed to prevent or minimize releases of potentially harmful substances.

The Company believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. For a discussion of the circumstances regarding the Company’s continued ability to recover these types of expenditures in rates, see Part II, Item 8. Financial Statements and Supplementary Data - Note B. Rate and Regulatory Issues and Contingencies.

Clean Air Act. See Item 3. Legal Proceedings, for a discussion of the potential liability for the past operations of Huntley and Dunkirk fossil generating stations.

ISO 14001. The Company’s Investment Recovery facility Environmental Management System (“EMS”) is certified to the International Organization for Standardization (“ISO”) 14001 standard. The Company’s distribution and transmission EMS are deemed to be in conformance with the ISO 14001 standard. The NY Transmission System EMS has been integrated into the National Grid USA Transmission EMS, which is already certified to ISO 14001. The NY EMS will be audited for Certification in June 2003.

Solid/Hazardous Waste. The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to investigate and remediate, as necessary to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary. See Part II, Item 8. Financial Statements and Supplementary Data - Note I. Commitments and Contingencies, “Environmental Contingencies,” for a discussion of the sites which are Company-owned.

EMPLOYEE RELATIONS

The Company’s work force at March 31, 2003 numbered approximately 5,500, of whom approximately 82 percent were union members. It is estimated that approximately 80 percent of the Company’s total labor cost is applicable to operation and maintenance and approximately 20 percent is applicable to construction and other accounts.

SEASONALITY

There is seasonal variation in electric customer load, usually peaking in the winter and summer months. The seasonality is correlated to the colder or warmer temperature in that more electricity is used for heating or cooling during those months.

There is a seasonal variation in gas customer sales, with loads usually peaking in the winter months. The seasonality is correlated to the colder temperatures in that more gas is used for heating during those months.

Also see Part II, Item 8. Financial Statements and Supplementary Data - Note P. Quarterly Financial Data (unaudited).

ITEM 2. PROPERTIES

ELECTRIC DELIVERY PROPERTIES

As of March 31, 2003, the Company’s electric delivery transmission and distribution systems were composed of:

748 substations with a rated transformer capacity of approximately 22,800,000 kilo-volt-amperes
approximately 9,400 pole miles of overhead and underground transmission lines
approximately 35,800 conductor miles of overhead distribution lines
about 5,800 cable miles of underground distribution cables

Only a part of the Company’s transmission and distribution lines are located on property owned by the Company. With respect to the Company’s transmission and distribution lines that are located on property not owned by the Company, the Company’s practice is to obtain right of way agreements.

The electric system of the Company is directly interconnected with other electric utility systems in New York, Massachusetts, Vermont, Pennsylvania, and the Canadian provinces of Ontario and Quebec, and indirectly interconnected with most of the electric utility systems through the Eastern Interconnection of the United States and Canada.

GAS DELIVERY

The Company distributes gas that it purchases from suppliers, and transports gas owned by others. As of March 31, 2003, the Company’s natural gas delivery system was comprised of approximately 8,400 miles of pipelines. Only a part of these natural gas pipelines and mains are located on property owned by the Company. With respect to natural gas pipelines and mains that are not located on property owned by the Company, the Company’s practice is to obtain right of way agreements.

SUBSIDIARIES

The Company has the following 100 percent owned subsidiaries:

NM Uranium, Inc. - has an interest in a uranium mining operation in Live Oak County, Texas. The mining operation is complete and the site has been reclaimed and restored.
NM Properties, Inc. - engages in real estate development and divestiture of property formerly owned by the Company. NM Properties, Inc. owns several subsidiaries and has interests in several joint ventures in carrying out its activities.
NM Receivables - facilitates the sale of an undivided interest in a designated pool of customer receivables, including accrued unbilled revenues. NM Receivables, LLC is owned by the Company (over 99.99 percent) and by NM Receivables Corp. II, which is a wholly owned subsidiary of the Company. See Item 8. Financial Statements and Supplementary Data, - Note A. Summary of Significant Accounting Policies and Note I. Commitments and Contingencies.

NATIVE AMERICAN MATTERS

There are five Native American Nations with reservations located in the vicinity of the Company’s service territory and facilities. The Company has held discussions and has been involved in legal proceedings with Native American Nations involving the Company’s high voltage transmission facilities on Nation lands, provision of electric service to customers on Nation lands, and the Nations’ land claims.

In June 2000, the Company entered into a 40-year agreement with the Seneca Nation to settle issues related to approximately 50 miles of high voltage transmission and distribution facilities located on the Seneca Nation’s Cattaraugus and Allegheny Reservations. The Company has entered into federally approved Electric Service Agreements with the Onondaga, Tuscarora and Seneca-Tonawanda Nations governing the provision of electric service to customers on their lands. The Company intends to seek similar agreements with the Oneida and Mohawk Nations to supplement existing federally approved agreements. The Company’s facilities are affected by land claim litigation involving the Cayuga, Oneida, Mohawk and Seneca Nations. A court has awarded damages to the Cayuga Nation that are payable by the State of New York. The land claim matters involving the Cayuga, Oneida, Mohawk and Seneca Nations have not been completely and finally resolved, although the St. Regis Mohawk Tribe recently entered into a Memorandum of Understanding with New York State that could lead to resolution of the Mohawk’s land claims against the Company. The Company continues to monitor the land claim litigation and, where necessary, defends its interests.

MORTGAGE LIENS

Substantially all of the Company’s operating properties are subject to a mortgage lien securing its mortgage debt.

ITEM 3. LEGAL PROCEEDINGS

The Company settled material litigation in April 2003 and currently has three material proceedings pending in addition to the environmental matters described in Note I to the financial statements in Item 8.

Fourth Branch Associates Mechanicville: In November 1993, Fourth Branch Associates Mechanicville (“Fourth Branch”) filed an action against the Company and several of its officers and employees in New York state court. The lawsuit arose from the Company’s termination of a contract for Fourth Branch to operate and maintain a hydroelectric plant the Company owned in the town of Halfmoon, New York. Fourth Branch’s complaint also alleged claims based on the inability of Fourth Branch and the Company to agree on terms for the purchase of power from a new facility that Fourth Branch hoped to construct at the Mechanicville site. The Parties agreed to settle the case in April 2003. Under the settlement, the Company will transfer the hydroelectric plant to Fourth Branch, subject to regulatory approval, and will make lump-sum payments to Fourth Branch and its bank in an aggregate amount that is immaterial to the Company.

Alliance for Municipal Power v. New York State Public Service Commission: On February 17, 2003, the Alliance for Municipal Power (“AMP”) filed with the New York state court a petition for review of decisions by the New York State Public Service Commission (the “PSC”) that maintain the PSC’s established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the Niagara Mohawk system and establish their own municipal light departments. Changes in the methodology for the calculation of the exit fee are not likely to have a material effect on Niagara Mohawk’s financial statements. However, AMP’s petition for review also challenges the lawfulness of Niagara Mohawk’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. If the court were to rule that Niagara Mohawk is not authorized to collect exit fees, and if the AMP communities proceeded with their plans to municipalize power, the Company could experience a significant shortfall of revenue. In addition, such a ruling could encourage other municipalities to consider municipalizing. The Company would seek to defer any lost revenue for eventual recovery from its remaining customers pursuant to the terms of its rate plan. Niagara Mohawk believes that it has strong defenses to AMP’s petition and is contesting the petition vigorously.

New York State v. Niagara Mohawk Power Corp. et al.: On January 10, 2002, New York State filed a civil action against the Company and NRG in federal district court in Buffalo, New York, for alleged violations of the federal Clean Air Act and related state environmental laws at the Dunkirk and Huntley power plants, which the Company sold in 1999 to NRG and its affiliates (collectively, “NRG”). The State alleged, among other things, that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls. The state sought, among other relief, statutory penalties under the Clean Air Act, which could have a maximum value of $25,000 to $27,500 per day per violation.

The Company and NRG moved to dismiss the complaint on statute of limitations and other grounds in 2002, and on March 27, 2003, the court granted the motions in part, holding that the violations of the Clean Air Act prior to November 1996 were barred by the federal five-year statute of limitations, and that related state statutory violations prior to November 1999 were barred by the state three-year statute of limitations. This eliminated the Company’s potential exposure to statutory daily penalties prior to these dates. At the same time, the court preserved the State’s non-regulatory claims against the Company and dismissed NRG from the suit.

On April 25, 2003, the State filed a motion for leave to amend the complaint to assert new claims against both the Company and NRG for unspecified amounts. Among other things, the state is seeking to reassert daily violations of the Clean Air Act going back to 1982, the time period covered by its original complaint. On May 30, 2003, the Company filed papers in opposition to the State’s petition. Oral argument has been scheduled for July 2, 2003.
Prior to the commencement of the enforcement action, on July 13, 2001, the Company filed a declaratory judgment action in New York State court in Syracuse against NRG seeking a ruling that NRG is responsible for the costs of pollution controls and mitigation that might result from the State’s enforcement action. As a result of NRG’s voluntary bankruptcy petition, filed in New York federal court for bankruptcy on May 14, 2003, the Company’s declaratory judgment action is stayed.

Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C.: The Company is engaged in a collection litigation to recover bills for station service rendered to the owners of three power plants (the “Plants”), which the Company sold in 1999 to three affiliates of NRG: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the “Defendants”). According to the Company’s records, as of March 31, 2003, the Defendants owed the Company approximately $33 million. After suit was filed, the parties agreed to stay the litigation to permit the FERC to try to resolve the dispute.

As noted above, NRG filed a voluntary bankruptcy petition in New York federal court for bankruptcy on May 14, 2003. The Company has received approval from the bankruptcy court to move forward in its FERC proceeding. Any FERC decision would determine the Company’s ability to charge the Defendants for station service electricity post-bankruptcy, but the collection of the outstanding station service bills as of the bankruptcy filing date will be governed by the bankruptcy court proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the last quarter of the fiscal year ended March 31, 2003.

PART II

ITEM 5. MARKET FOR THE REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The common stock of the Company is held solely by Niagara Mohawk Holdings, Inc., and therefore indirectly by National Grid USA and National Grid Transco plc. There is no public trading market for the Company’s common stock, and the Company sold no equity securities during the period covered by this Annual Report. For information about the Company's payment of dividends and restrictions on those payments, see Item 6, Selected Financial Data, and Item 8, in the Notes to the Financial Statements.

ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

The following tables set forth selected financial information for the Company for the year ended March 31, 2003, the sixty days ended March 31, 2002, thirty days ended January 30, 2002, three months ended March 31, 2001, and each of the four years during the period ended December 31, 2001, which have been derived from the financial statements of the Company, and should be read in connection therewith.

On January 31, 2002, the Company was acquired by National Grid in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. As discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements, the following selected financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.

		Year Ended	60 Day Period	30 Day Period	Three months
(in 000's except		March 31,	Ended March	ended January	ended March	Year Ended December 31,
per share data)		2003	31, 2002	30, 2002	31, 2001	2001	2000	1999	1998
		(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)

Operating Revenues		$ 4,019,450	$ 689,705	$ 362,622	$ 1,179,706	$ 4,114,713	$ 3,865,949	$ 3,827,340	$ 3,826,373

Net Income (Loss)		125,871	30,646	(20,941)	34,010	19,358	(27,646)	(9,661)	(147,894)

Income (loss) from		*	*	*	*	*	*	*	(0.89)
	continuing operations per
	average common share

Total assets		12,243,759	12,101,588	**	12,037,039	11,436,554	12,270,324	12,418,508	13,835,987

Long-term debt		3,953,989	4,146,642	**	4,674,004	4,419,822	4,678,963	5,042,588	6,417,225

Mandatorily redeemable		-	-	**	53,750	50,700	53,750	61,370	68,990
	preferred stock

Dividends paid per		*	*	*	*	*	*	*	-
	common share

* All of the Company’s shares of common stock are owned by its parent company, therefore, dividend information and per share data is not relevant.

** Balance Sheet information as of the 30 day period ended January 30, 2002 is not provided.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

MERGER WITH NATIONAL GRID

On January 31, 2002, the acquisition of Holdings by National Grid was completed for a value of approximately $3.0 billion in cash and American Depositary Shares. The acquisition is being accounted for by the purchase method, the application of which, including the recognition of goodwill, is being recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. The purchase accounting method required the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in an increase to the Company’s pension and postretirement benefit liability in the amount of approximately $440 million, with a corresponding offsetting increase to a regulatory asset account. See “Merger Rate Plan”, below, for a discussion of the anticipated future results on the Company. See Item 8. Financial Statements and Supplementary Data, - Note H. Pension and Other Retirement Plans for a discussion of the Company’s pension and postretirement benefit plans.

VERO

In January 2002, the Company made a voluntary early retirement offer (“VERO”) to 302 eligible employees in targeted areas where significant workforce reductions were necessary in the combined organization, primarily corporate administrative functions such as finance, human resources, legal and information technology. Eligible employees were non-union employees in the targeted functions who will be age 55 with at least ten years of pension service by March 31, 2004. The Company sets the actual retirement dates for individuals based on operational needs. Retirement dates will conclude no later than April 1, 2004.

The number of eligible employees that accepted the VERO was 267 and most retired by June 30, 2002. Under the Merger Rate Plan, the Company is allowed to record a regulatory asset for separation and early retirement costs. The amortization of such regulatory asset is occurring over ten years, with approximately 69 percent of the amortization of the regulatory asset occurring within the first three years. On January 31, 2002, the Company recorded a regulatory asset of $53 million related to the VERO. This regulatory asset had a balance of $30 million at March 31, 2003.

REGULATORY AGREEMENTS AND THE RESTRUCTURING OF
THE REGULATED ELECTRIC UTILITY BUSINESS

Merger Rate Plan. On November 28, 2001, the PSC approved the Merger Rate Plan. This rate plan became effective on January 31, 2002, the closing of the merger. Key terms of the plan are as follows:

Net customer savings of approximately $1 billion over the next ten years, compared with rates projected without the merger. This includes a $152 million reduction in delivery charges compared to rates approved in the Company’s Power Choice rate agreement, followed by stabilized delivery charges for ten years, subject to limited adjustments. This equals an expected reduction in the Company electricity delivery rates of more than eight percent, which results in a projected five percent decrease in overall electricity bills, including a projected commodity cost, which will continue to be borne by customers.
Price-stabilized commodity service for residential and commercial customers for several years, giving those customers significant protection from severe fluctuations in the generation marketplace.
Agreement to forgo the collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates.
Permitted recovery of and a return on the remaining MRA regulatory asset, which consists of recoverable costs to terminate or amend IPP contracts under the MRA.
Agreement to expand the Company’s annual upstate New York economic development efforts by $12.5 million.
The extension by 16 months of the existing multi-year gas rate settlement agreement, resulting in a freeze in natural gas delivery rates through December 2004.
Extension of the Low Income Customer Assistance Program and introduction of a special low-income rate.
Establishment of a Service Quality Assurance Program that calls for up to $24 million in annual penalties or more under certain conditions, if defined customer service goals are not achieved.
The continuation of the stranded cost recovery provisions under Power Choice with slight modifications.
The sharing with customers 50 percent of cumulative earnings in excess of an 11.75 percent return on common equity.

Although rates will be lower under the Merger Rate Plan, the Company believes cost savings from the merger should enable it to improve its operating results.

Generation Asset Sales. Federal and state mandates have encouraged the separation of generation from transmission and distribution in order to promote competition and reduce prices to customers. In accordance with these mandates, the Company has divested all of its generation plants and operates primarily in the transmission and distribution sectors. In 1999, the Company completed the sale of its coal-fired generation plants, its hydro generation plants, and its oil and gas-fired generation plant at Oswego for $860 million. In 2000, the Company completed the sale of its oil and gas-fired plant at Albany for $48 million. In January 2001, the Company completed the sale of its 25 percent interest in the Roseton Steam Station for approximately $84 million. In November 2001, the Company sold its nuclear assets to Constellation for approximately $603 million. The Company also executed PPAs with the buyers of the formerly owned fossil and hydro assets, which are designed to help the Company meet rate reduction and price cap commitments as well as expected demand as the provider of last resort. The Company also signed PPAs with Constellation to purchase energy at negotiated prices through 2011 and revenue sharing agreements for ten years thereafter. See Item 8. Financial Statements and Supplementary Data, Note B. Rate and Regulatory Issues and Contingencies, Note I. Commitments and Contingencies, and Note J. Derivatives and Hedging Activities, for a further discussion of the terms of these agreements.

Following write-offs agreed to by the Company, the PSC Order approved the sale of the nuclear assets and provided for the deferral and future recovery of the remaining nuclear stranded costs. The Company began to amortize the regulatory asset related to the loss on the sale of the nuclear assets immediately subsequent to such sale. Prior to implementation of the Merger Rate Plan, the Company had a regulatory asset of $1,074.6 million for the net loss on the sale of its nuclear generation assets. Under the Merger Rate Plan, the Company agreed to forgo collection of approximately $850 million in nuclear-related costs that otherwise would have been collected in rates. The nuclear regulatory asset that remained after such a write-off is included in the Company’s balance sheet as part of “Merger rate plan stranded costs.”

FERC Proceedings. The FERC is contemplating major changes to the regulatory structure that governs the Company’s business. Several proposals are under consideration, any of which may affect how the Company does business. The Company cannot predict which or how many of the proposals the FERC will adopt or in what form, or whether they will have a material impact on the Company’s financial position or results of operations.

Regional Transmission Organizations: The FERC has indicated that it wants regional transmission organizations ("RTOs") formed that would cover a larger geographic area than independent system operators ("ISOs"). In response to an order by the FERC, participants in the ISO New England (“ISO-NE”), the New York ISO, and the Pennsylvania-New Jersey-Maryland ISOs took part in a mediation to establish an RTO. The FERC has not yet ruled on the mediator’s report. Pending the FERC’s ruling, transmission owners, including the Company, have been working to develop an alternative RTO structure. It is not clear what structure will emerge from these negotiations or what the geographic scope will be of the RTO in which the Company participates. In August 2002, the New York and New England ISOs filed a proposal with the FERC to form an RTO but withdrew it in November 2002 after several parties, including National Grid USA, filed protests.

Standard Market Design: In July 2002, the FERC issued a formal notice of proposed rulemaking ("NOPR") on standard market design ("SMD"). The proposed rules address transmission pricing and planning, the role of merchant transmission, and other issues that would directly affect the Company. The FERC issued a White Paper on April 28, 2003 outlining a proposed wholesale power market platform that it would require in any final rules in this proceeding. The White Paper embodies FERC's response to the comments that it received in this proceeding. FERC states that it intends to issue a rule requiring that public utilities join independent entities (either an RTO or an ISO) that would be responsible for transmission service, tariff design, system operations and markets within a region. States would have a significant role in regional transmission planning, tariff design and in ensuring resource adequacy. Transmission owners that are market participants would have limited authority to manage transmission. Independent transmission companies may manage a broader set of functions.

The FERC has also proposed that it assume jurisdiction over transmission rates to retail customers. In prior orders, the FERC has held that deliveries at retail will continue to be subject to state-approved retail charges as well as the FERC-approved transmission rate, even if the delivery is made over transmission facilities. The introduction of an independent entity with its own transmission tariff would require coordination between the state and federally approved charges to avoid bypass of costs embedded in such state approved charges.

In addition, to the extent the Company wishes to pursue opportunities related to transmission projects, the FERC rulings in the SMD proceeding and other proceedings may limit the Company's ability to do so. The Company cannot predict when the FERC will issue final rules on SMD, or in what form, or if they will have a material impact on the Company’s financial position or results of operations.

On July 12, 2002, the U.S. Court of Appeals issued an order concerning Pennsylvania-New Jersey-Maryland ISO’s relationship with its transmission owners. This order was favorable precedent to the Company because it suggested that transmission owners that join ISOs still maintain significant authority to propose transmission rates and to withdraw from such ISOs. On December 19, 2002 and May14, 2003, however, the FERC issued decisions that appear to narrow this authority. On May 20, 2003, the U.S Court of Appeals issued a ruling declaring that the FERC’s December 19, 2002 order had violated the Court’s mandate. It is not clear whether the FERC’s more recent decision will stand, but the uncertainty surrounding this issue will likely affect the Company’s relationship with the NYISO and with any future RTO.

Standards of Conduct: In September 2001, the FERC initiated a NOPR regarding affiliate standards of conduct in both the electric and gas industries. In its proposed rules, the FERC proposed a broad definition of "energy affiliate," which would include the Company’s affiliate National Grid USA Service Company, Inc., as well as the Company’s electric distribution company affiliates. If the FERC were to adopt these rules as proposed, the Company would have to change the way it interacts with its so-called energy affiliates in a manner that could increase costs.

Incentive Pricing: In January 2003, the FERC proposed a pricing policy statement indicating that it may provide incentives to transmission owners to join a RTO, an independent transmission company and to invest in new facilities. The FERC has solicited comments on this statement, and the Company cannot predict what the final policy statement will say or whether it will have a material impact on the Company’s financial position or results of operations.

PSC Issues. In connection with an audit performed by PSC Staff, the Company reached a settlement with the Staff that resolves all issues associated with its pension and other postretirement benefit obligations for the period prior to the acquisition of the Company by National Grid. The settlement is subject to approval by the full New York State Public Service Commission. Among other things, the settlement covers the funding of the Company’s pension and post-retirement benefit plans. Under the settlement, the Company agreed to provide $100 million of tax-deductible funding by April 30, 2003 (which it funded in March 2003), and an additional $209 million, on a tax-deductible basis, by December 31, 2011. The Company will earn a rate of return of at least 6.60 percent on any portion of the $209 million that it funds before December 31, 2011, plus 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent. This settlement resolves all PSC Staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.

As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC. Specifically, the Company has requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (“NYPA”) hydropower revenues in its commodity adjustment clause, and is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. In addition, the Company has filed a modification to its tariff and a proposal to refund an additional $7 million associated with the recovery of other NYPA hydropower costs. These filings are pending before the PSC, and the Company cannot predict the outcome of the filings.

OTHER

Change of Fiscal Year. At the time of the merger with National Grid, the Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. The Company made this change in order to align its fiscal year with that of its new parent company, National Grid. The Company’s first new full fiscal year began on April 1, 2002 and ended on March 31, 2003.

CRITICAL ACCOUNTING POLICIES

There are certain critical accounting policies that are based on assumptions and conditions that if changed could have a material effect on the financial condition, results of operations and liquidity of the Company. The following accounting policies are particularly important to the financial condition and results of operations of the Company: regulatory accounting (including the collection of purchase power costs through the commodity adjustment clause and purchased gas through the gas cost collection mechanism), goodwill accounting and derivative accounting.

Regulatory Accounting
Electric utilities are subject to certain accounting standards that are generally not applicable to other business enterprises. The Company applies the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“FAS 71”), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board (“FASB”) concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs.

The Company has received authorization from the PSC to recover through its Competitive Transition Charges (“CTCs”) substantially all of the costs associated with its former generating business not recovered through the divestiture. The CTC is a mechanism that was established in the Company’s Power Choice agreement to recover stranded costs from customers. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company’s business, including the recovery of its stranded costs, remains under cost-based rate regulation.

Under the Merger Rate Plan, the Company will earn a return on all of its regulatory assets. In the event the Company determines, as a result of lower than expected revenues or higher than expected costs, or both, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations and adversely affect the Company’s ability to pay dividends.

Under the Merger Rate Plan, the Company’s remaining electric business (electric transmission and distribution) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply SFAS No. 71 to these businesses. Also, the Company’s IPP contracts, including those restructured under the MRA, as well as the PPAs entered into in connection with the generation divestiture, continue to be the obligations of the regulated business.

Derivatives
The FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), as amended, which the Company adopted on January 1, 2001. SFAS No. 133 requires that companies identify all derivative instruments in use, record all derivatives on the balance sheet as assets or liabilities measured at fair value and adjust the fair value at each financial reporting period. Depending on the use of the derivative and its qualification as a hedge, the changes in fair value either will be recorded directly in earnings or will be deferred and matched with the settlement of the transaction being hedged. The Company’s derivatives are listed on the Consolidated Balance Sheets as “Derivative Instruments” or “Current liabilities—other.”

Upon implementation of SFAS No. 133, the Company designated several financial instruments as derivatives and qualified certain of these instruments as hedges. Those derivative instruments that did not qualify for hedge accounting were the result of regulatory rulings and therefore, the earnings impact of the adoption of SFAS No. 133 was offset by regulatory assets or liabilities as directed by SFAS No. 71. The result was no impact on earnings for the adoption of SFAS No. 133 by the Company.

Revenue Recognition
The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The Company estimates unbilled revenues using the prior month’s average daily revenue for each billing cycle.

Goodwill
The company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for impairment at least annually. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.

Pensions
The Company has recognized an additional minimum pension liability of $269 million on its balance sheet reflecting an underfunded pension obligation. The Company would normally record a charge to other comprehensive income as an offset to this entry. However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset.

For further discussion of Critical Accounting Policies see Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Item 8. Financial Statements and Supplementary Data, Note A. Summary of Significant Accounting Policies, Note B. Rate and Regulatory Issues and Contingencies and Note J. Derivatives and Hedging Activities.

RESULTS OF OPERATIONS

The following discussion and analysis highlights items that significantly affected the Company’s operations during the year ended March 31, 2003, the three months ended March 31, 2002 and 2001, and the twelve-month periods ended December 31, 2001 and 2000. See “Merger Rate Plan” for a further discussion of how the closing of the merger with National Grid will impact the future results of the Company. Results of operations through January 30, 2002 reflect the Power Choice rate plan and the Company’s generation assets sales. Reported earnings under Power Choice were substantially depressed as a result of the regulatory treatment of the MRA regulatory asset. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. It should also be read in conjunction with Item 8. Financial Statements and Supplementary Data, and other financial and statistical information appearing elsewhere in this report.

The Company now reports results on a fiscal year ending March 31, which has affected comparability to prior results. To assist in the comparability of the Company’s financial results and discussions, results of operations for the three months ended March 31, 2002 include results for the 30 day period of the predecessor and the 60 day period of the successor and are designated as “combined.” Management has based its discussion and analysis of results of operations for the three month period ending March 31, 2002 as compared to the three month period ending March 31, 2001 on the combined results of operations for the three month period ending March 31, 2002.

EARNINGS

Net income for the twelve months ended March 31, 2003 increased approximately $107 million compared to the twelve months ended December 31, 2001. This increase is primarily due to the implementation of the Merger Rate Plan, a nuclear write-off in 2001 and the sale of the Company’s generation business, which was completed in 2001. Under the Merger Rate Plan, the Company has lowered delivery rates leading to lower operating revenues. However, this has been offset by lower operating expenses as a result of merger savings, the sale of the generation business and lower interest expense due to refinancing and the continuing repayment of debt.

Net income for the three months ended March 31, 2002 was approximately $24 million lower than the three month period ended March 31, 2001. A decline in operating income due to the effect a warm winter had on the gas business and increased other operation and maintenance costs was partially offset by lower interest expense due to the repayment of debt during 2002.

Net income for the twelve months ended December 31, 2001 increased approximately $47 million compared with the twelve months ended December 31, 2000. This is primarily due to lower interest expense due to the repayment of debt during 2001. Earnings for 2001 also reflect the effects the generation asset sale namely increased purchased electricity offset by lower depreciation, property tax, labor and fuel expenses.

REVENUES

Electric revenues decreased $82 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The table below details components of this fluctuation.

Change in Electric Revenue from the twelve months ended
December 31, 2001 to March 31, 2003
(In Millions)

	Retail sales		$ (1)
	Sales for resale		(61)
	Transmission wheeling		(23)
	Other		3
		Total	$ (82)
			=========

The decrease in sales for resale is primarily attributable to lower sales to the NYISO. Transmission wheeling revenue was lower primarily due to lower NYISO Transmission Congestion Contracts (“TCC”) auction revenues. Although there was almost no change in retail sales, revenues increased due to higher delivery only revenue by $88 million which were offset by lower electric rates under the Merger Rate Plan.

Electric revenues decreased $1 million in the three months ended March 31, 2002 as compared to the same period in the 2001 and increased $186 million in the calendar year 2001 as compared to the same period in 2000.

Electric revenues decreased in the three months ended March 31, 2002 as compared to the same period in 2001 primarily as a result of lower sales to ultimate customers due to the warmer weather. In addition, transmission revenues decreased $9 million primarily due to the introduction of the transmission revenue adjustment mechanism on September 1, 2002, which reduced transmission revenues by $7 million. These decreases were partially offset by an increase in distribution of energy of $19 million; higher electric rates since September 2001 of $21 million since the commodity cost reflected in rates was higher, partially offset by lower delivery rates; an increase in systems benefit charge revenue recoveries of $6 million and an increase in unbilled revenues of $6 million. In accordance with Power Choice and the Merger Rate Plan, the Company recognizes changes in accrued unbilled revenue in its results of operations. The systems benefits charge is offset in other operation and maintenance expense. The decrease in electric sales to ultimate consumers and the increase in distribution of energy reflect the growing number of customers that purchase electricity from other suppliers.

The increase in electric revenues in 2001 as compared to 2000 is primarily due to an increase in sales for resale of $118 million as a result of higher sales to the NYISO; higher overall rates since September 2001 of $37 million since the commodity cost reflected in rates was higher, partially offset by lower delivery rates; an increase in miscellaneous revenues of $27 million; an increase in transmission revenues of $11 million and an increase in the systems benefit charge revenue recoveries of $24 million.

Electric kilowatt-hour sales were approximately 38.8 billion for the twelve months ended March 31, 2003, 9.4 billion and 9.3 billion for the three months ended March 31, 2002 and the same period in 2001, respectively, and 39.9 billion in the calendar year 2001, and 36.3 billion in the calendar year 2000.

Electric deliveries for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001 decreased 1.1 billion KWh. The decrease is primarily due to a decrease in sales for resale of 2.1 billion KWh as a result of lower sales to the NYISO and lower sales to commercial and industrial customers of 2.1 billion KWh offset by increased residential sales of .6 billion KWh and an increase in delivery only of energy of 2.5 billion KWh.
Electric deliveries for the three months ended March 31, 2002 as compared to the same period in 2001 increased 0.1 billion KWh and increased 3.6 billion KWh in the calendar year 2001 as compared to the same period in 2000. The increase in the three months ended March 31, 2002 as compared to the same period in 2001 is primarily due to an increase in sales for resale of 0.7 billion KWh as a result of higher sales to the NYISO and an increase in distribution of energy of 0.2 billion KWh, partially offset by a decrease in sales to ultimate customers of 0.7 billion KWh primarily due to the milder weather.

The increase in calendar year 2001 is primarily due to an increase in sales for resale of 4.1 billion KWh as a result of higher sales to the NYISO, partially offset by a decrease in sales to ultimate customers of 0.3 billion KWh due to the milder weather in 2001 as compared to 2000.

Gas revenues decreased $13 million for the twelve-months ended March 31, 2003 compared to the twelve-months ended December 31, 2001 primarily due to a decrease in the commodity cost of purchased gas offset somewhat by an increase in delivery revenue. The primary reason for the increase in gas delivery revenue is higher rates which reflect the inclusion of the state income tax. The decrease in the cost of purchased gas is explained below under “gas purchased” expense. The table below details components of the gas revenue fluctuation.

Change in Gas Revenue from the twelve-months ended

December 31, 2001 to March 31, 2003

(In Millions)


Cost of Purchased Gas		$ (26)
Delivery Revenue		18
Other		(5)
	Total	$ (13)
		========

Gas revenues decreased $127 million in the three months ended March 31, 2002 from the comparable period in 2001 due to lower gas prices being passed through to customers and milder weather in 2002. Gas revenues increased $63 million in the calendar year 2001 primarily as a result of higher gas prices being passed through to customers in early 2001, despite overall milder weather in 2001.

The commodity cost of purchased gas has no impact on the Company’s net income because the actual commodity costs are passed through to customers on a one-to-one basis.

Gas sales for the twelve months ended March 31, 2003, excluding transportation of customer-owned gas and spot market sales, were 69 million Dth, a 5.8 percent increase from the twelve-months ended December 31, 2001. The increase was primarily due to the impacts of weather as offset by migration to delivery only service. Gas sales in the calendar year 2001, excluding transportation of customer-owned gas and spot market sales, were 64 million Dth. Gas sales in the three months ended March 31, 2002, excluding transportation of customer-owned gas and spot market sales, were 28 million Dth, a 19.6 percent decrease from the same period in 2001. The decrease was primarily due to milder weather in the three months ended March 31, 2002 as compared to the same period in 2001.

Gas sales in the calendar year 2001, excluding transportation of customer-owned gas and spot market sales, were 64 million Dth, a 9.7 percent decrease from 2000. The decrease in gas sales is primarily attributable to milder weather in 2001 as compared to 2000. Gas delivered was also negatively impacted by a decrease in transportation volumes of 14 million Dth as a result of customers purchasing less gas from other gas providers.

OPERATING EXPENSES

The Company’s electricity purchased increased $290 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, $52 million in the three months ended March 31, 2002 as compared to the same period in 2001 and $160 million in calendar year 2001 as compared to calendar year 2000, primarily as a result of the timing of the various sales of the Company’s generation assets. The Company now purchases all of its load requirement through the NYISO, or through other parties under long-term PPAs (for a discussion of the portion of the purchases that are hedged, see Item 7A. Quantitative and Qualitative Disclosure about Market Risk - “Electricity Price Risk”). Although the prices the Company must pay for electricity are higher than the fuel costs incurred when the assets were owned, the Company avoids operating costs from running these plants, including labor, fuel, real estate taxes, and depreciation.

Significantly higher natural gas prices impacted the Company’s fuel and purchased power costs during the third and fourth quarters of 2000 and in early 2001, principally because restructured contracts with IPPs began indexing to natural gas prices in July 2000. Fuel and purchased power costs were also higher in the third and fourth quarters of 2000 and in early 2001 because of an indexed contract with the new owner of the Albany generating station and an indexed contract with an IPP not part of the MRA. The Company’s continued 25 percent ownership in the Roseton generating station also increased fuel and purchased power costs in 2000. The Roseton generating station was sold in January 2001. The Albany and Roseton stations are both fueled by oil or natural gas. With respect to its exposure to the restructured contracts with the IPPs and the Albany contract, the Company takes steps to hedge against further volatility in natural gas prices, largely by purchasing New York Mercantile Exchange (“NYMEX”) gas futures contracts. On September 1, 2001, the rate plan changes under the Power Choice agreement allowed for the pass-through of most commodity-related costs to customers. This pass-through of commodity costs to customers continues under the Merger Rate Plan.

IPP purchases decreased by $17 million in the three months ended March 31, 2002 as compared to the same period in 2001, since the Company entered into an agreement with one IPP that reduced the amount of energy it had to buy from them. In the three months ended March 31, 2001, the Company paid that IPP $18 million. The Company did not make any payments to that particular IPP in the same period in 2002. IPP purchases were lower in calendar year 2001 as compared to 2000 due to a decrease in hydro IPP production as a result of a reduction in water flow because of drier weather. The change in the deferral for electricity purchased is due to the regulatory treatment of the hydro PPA as discussed in Item 8. Financial Statements and Supplementary Data - Note B. Rate and Regulatory Issues and Contingencies.

The Company had no fuel for electric generation expense in either the twelve-months ended March 31, 2003 or the three months ended March 31, 2002 because it had sold all of its generation assets in earlier periods. Fuel for electric generation decreased $37 million in calendar year 2001 as compared to 2000, primarily as a result of the timing of the various sales of the Company’s generation assets. In addition, generation from the Company’s nuclear plants was reduced due to an extended outage of one of the nuclear plants in 2001.

The Company’s gas purchased expense decreased approximately $26 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001. The decrease is a result of lower gas prices in the current period partially offset by increased sales attributable to the colder winter weather conditions than in the comparable prior period. Quantities purchased and withdrawn from storage were up 5.7 million Dth. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, decreased to $5.57 in the twelve-months ended March 31, 2003 from $6.45 for the twelve-months ended December 31, 2001.

Gas purchased expense decreased $120 million in the three months ended March 31, 2002 as compared to the same period in 2001 primarily as a result of lower natural gas prices. Dth purchased and withdrawn from storage were down 0.4 million Dth. The Company’s net cost per Dth, as charged to expense, including the effects of the gas commodity cost adjustment clause, decreased to $3.97 in the three months ended March 31, 2002 from $7.53 the same period in 2001.

The Company’s gas purchased expense increased $62 million in 2001, primarily as a result of higher natural gas prices which more than offset reduced sales volumes. Dth purchased and withdrawn from storage were down 16.1 million Dth. The Company’s net cost per Dth, as charged to expense, including the effects of the gas commodity cost adjustment clause, increased to $6.45 in calendar year 2001 from $4.42 in calendar year 2000.

For a discussion of hedging of gas purchases, see Item 7A. Quantitative and Qualitative Disclosures about Market Risks – “Gas Supply Price Risk.”

Other operation and maintenance expense decreased $112 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001. The decrease is primarily attributable to the sale of its generation assets, especially its nuclear generation, in that the labor, fuel, and real estate taxes for these generation assets are no longer paid for. Expense was also reduced due to lower transmission costs from fewer TCCs purchased from NYISO and merger integration savings in the current period. TCCs confer the right to collect or obligation to pay congestion charges for a single megawatt of energy transmitted between two geographic locations.

Other operation and maintenance expense for the Company had increased $27 million in the three months ended March 31, 2002 as compared to the same period in 2001, primarily as a result of increased employee welfare expense primarily due to separation costs of $7 million, increased pension and other postretirement benefits expense of $14 million, increased compensation accruals of $6 million, incremental merger related costs of approximately $11 million, incremental storm expense of $14 million and a higher systems benefit charge of $6 million. The systems benefits charge is offset in electric revenues. These increases were partially offset by lower nuclear operation expense of $36 million as a result of the sale of the nuclear assets.

Other operation and maintenance expense for the Company has increased $65 million in 2001, primarily as a result of an increase in transmission expense of $34 million in part due to TCCs purchased through the auction process conducted by the NYISO, an increase in bad debt expense of $8 million which reflects the impact of the higher natural gas prices being passed on to customers, a higher systems benefit charge of $23 million, higher compensation accruals of $13 million and higher pension expense of $19 million. The systems benefits charge and the TCC expense are both offset in electric revenues. The incremental merger related costs for 2001 were approximately $4 million. In addition, the insurance proceeds and disaster relief associated with the 1998 ice storm restoration effort was $6 million in 2001 as compared to $30 million in 2000. Offsetting these increases were lower injuries and damages expense of $12 million, lower employees welfare expense of $6 million, lower customer services system expense of $7 million, lower non-nuclear operation and maintenance expense as a result of the sale of the non-nuclear assets of $16 million and lower nuclear operation and maintenance expense, net of deferrals and amortizations, of $21 million.

In 2001, the Company recorded a non-cash write-off of $123 million before tax, which is reflected on the disallowed nuclear investment costs line item in accordance with the PSC Order approving the sale of the nuclear assets.

Amortization of stranded costs decreased $243 million for the twelve-months ended March 31, 2003 as compared to the twelve-months ended December 31, 2001, decreased by $27 million in the three months ended March 31, 2002 as compared to the same period in 2001 and increased by $18 million in 2001 and increased $12 million for 2000. The decreases are from the difference in rate plans. Under Power Choice, the MRA regulatory asset was being amortized ratably over ten years. Under the Merger Rate Plan, which began on January 31, 2002, the MRA regulatory asset and other stranded costs are being amortized unevenly over ten years, with larger amounts being amortized in the latter years. See Item 8. Financial Statements and Supplementary Data - Note B. Rate and Regulatory Issues and Contingencies - “Merger Rate Plan Stranded Costs” for a further discussion of the ratemaking treatment related to this regulatory asset.

Depreciation and amortization expense decreased approximately $94 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, decreased approximately $28 million in the three months ended March 31, 2002 as compared to the same period in 2001, and decreased by $20 million in calendar year 2001 as compared to 2000, primarily as a result of the sale of the Company’s generation assets at various times during 1999 through 2001.

Other taxes increased approximately $19 million for the year ended March 31, 2003 as compared to the year ended December 31, 2001, due to a decrease for the Gross Receipts Tax (“GRT”) Power for Jobs tax credit. In 2001, the Company amended prior years’ tax returns (1998 through 2000), thereby increasing the amount of Power for Jobs credit recorded in 2001. This increase was partially offset by a reduction in property taxes primarily resulting from the sale of the nuclear assets in November 2001.

Other taxes increased $11 million in the three months ended March 31, 2002 as compared to the same period in 2001. In the first three months ended March 31, 2001, the Company received $22 million in GRT Power for Jobs credits due to a prior year true-up to actual filed returns. GRT credits of $1.2 million were received in the same period in 2002 due to a prior year true-up. This increase was partially offset by a reduction in the GRT tax rate of $6 million and a reduction in property taxes of $4 million primarily resulting from the sale of the nuclear assets in November 2001.

Other taxes for the Company decreased in 2001 due to an increase in GRT credits ($40 million) received primarily due to an increase in the customers in the Company’s service territory that participate in New York State’s Power for Jobs program, a reduction in the GRT tax rate ($4 million) primarily as a result of the state tax law changes and a reduction in property taxes of $5 million primarily resulting from the sale of the nuclear assets in November 2001.

The Company’s income taxes increased $84 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. The increase is due primarily from increased book taxable income for the twelve months ended March 31, 2003 and recording of previously deferred investment tax credits related to the sale of the nuclear assets of $80 million and the recording of the tax benefit of $43 million related to the non-cash write-off of $123 million of disallowed nuclear investment costs in 2001. Income taxes increased approximately $6 million in the three months ended March 31, 2002 primarily due to higher book taxable income. The 2001 increase in income taxes of approximately $16 million is primarily due to higher book taxable income. See Item 8. Financial Statements and Supplementary Data, - Note G. Federal, State and Foreign Income Taxes, for a reconciliation of the tax computed at the statutory rate.

The Company’s other income (deductions) decrease $74 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001. This is primarily attributable to the Company recording $80 million of previously deferred investment tax credits related to the sale of the nuclear assets in 2001.

Other income (deductions) in the three months ended March 31, 2002 decreased $4 million primarily due to carrying charges on IPP buy out contract adjustments of $2 million and, in the three months ended March 31, 2001, other income reflected the recording of a non-cash incentive related to generation asset sales of $7 million for which there was no corresponding amount in the three months ended March 31, 2002.

The Company’s other income (deductions) increased $92 million in the year ended December 31, 2001 compared to the same period in 2000. This is primarily attributable to the Company recording $80 million of previously deferred investment tax credits related to the sale of the nuclear assets in 2001.

The Company’s interest charges decreased $33 million in the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001, decreased $13 million in three months ended March 31, 2002 as compared to the three months ended March 31, 2001, and decreased $43 million in 2001 compared 2000, mainly due to the repayment and early repayment of debt during 1999 through March 31, 2003, and to a lesser extent, lower rates.

Preferred dividends decreased $25 million in the twelve months ended March 31, 2003 from the twelve months ended December 31, 2001 due to preferred stock redemptions, decreased $0.1 million from the three months ended March 31, 2002 as compared to the same period in 2001 due to preferred stock redemptions, decreased $0.6 million from 2000 to 2001 due to sinking fund redemptions.

EFFECTS OF CHANGING PRICES

The Company is especially sensitive to inflation because of the amount of capital it typically needs and because its prices are regulated using a rate-base methodology that reflects the historical cost of utility plant.

The Company’s consolidated financial statements are based on historical events and transactions when the purchasing power of the dollar was substantially different than now. The effects of inflation on most utilities, including the Company, are most significant in the areas of depreciation and utility plant. The Company could not replace its utility assets for the historical cost value at which they are recorded on its books. In addition, the Company would not replace these with identical assets due to technological advances and competitive and regulatory changes that have occurred. In light of these considerations, the depreciation charges in operating expenses do not reflect the cost of providing service if new facilities were installed. See “Long Term” below for a discussion of the Company’s future capital requirements.

LIQUIDITY AND CAPITAL RESOURCES

Short Term. At March 31, 2003, the Company’s principal sources of liquidity included cash and cash equivalents of $34 million and accounts receivable of $543 million. The Company has a negative working capital balance of $659 million primarily due to long-term debt due within one year of $612 million and short-term debt of $198 million. Ordinarily, construction related short-term borrowings are refunded with long-term securities on a periodic basis. This approach generally results in a working capital deficit. Working capital deficits may also be a result of the seasonal nature of the Company’s operations as well as the timing of differences between the collection of customer receivables and the payments of fuel and purchased power costs. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund such deficits as necessary in the near term.

The Company’s outstanding short-term debt of $198 million consists of borrowings from other National Grid USA companies through the money pool. For a further discussion of the money pool, see Item 8. Financial Statements and Supplementary Data - Note F – Bank Credit Arrangements.

Net cash from operating activities was $599 million for the Company for twelve months ended March 31, 2003 which funded its acquisition of utility plant and the retirement of certain debt obligations.

The Company’s long-term debt due within one year is $612 million at March 31, 2003. In addition, construction expenditures planned within one year are estimated to be $297 million. These capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid USA companies through the Money Pool or directly.

The Company’s net cash used in investing activities increased $66 million for the twelve months ended March 31, 2003 compared to the twelve months ended December 31, 2001. This increase was primarily as a result of more proceeds being received in the twelve months ended twelve months ended December 31, 2001 from such generation sales than in the twelve months ended March 31, 2003 by $104 million. This was partially offset by an increase in cash provided by other investments of $35 million.

The Company’s net cash used in financing activities decreased $8 million for the twelve months ended March 31, 2003 as compared to the twelve months ended December 31, 2001, primarily due to a decrease in the redemption of long-term debt, offset by an increase in common dividends to Holdings.

Long Term. The Company’s total capital requirements consist of amounts for its construction program, working capital needs, and maturing debt issues. Construction expenditure levels for the energy delivery business are generally consistent from year-to-year.

The following table summarizes long-term contractual cash obligations of the Company:


			Payment due in:
			Less than	1 - 3	4 - 5	After 5
($'s in Millions)			1 year	years	years	years	Total

Long-term Debt			$ 612	$ 1,073	$ 479	$ 2,401	$ 4,565
Electric purchase power commitments			619	1,020	861	1,869	4,369
Gas supply commitments			193	213	75	22	503
Derrivative swap commitments*			192	299	274	29	794
Construction expenditures**			297	N/A	N/A	N/A	297
	Total contractual cash obligations		$ 1,913	$ 2,605	$ 1,689	$ 4,321	$ 10,528

	*	- Forecasted, actual amounts could differ based on changes in market conditions
	**	- Budgeted amount in which substantial commitments have been made. Amounts
		beyond 1 year are budgetary in nature and not considered contractual obligations
		and are therefore not included.

In connection with an audit performed by PSC Staff, the Company reached a settlement with the Staff that resolves all issues associated with its pension and other postretirement benefit obligations for the period prior to the acquisition of the Company by National Grid. The settlement is subject to approval by the full New York State Public Service Commission. Among other things, the settlement covers the funding of the Company’s pension and post-retirement benefit plans. Under the settlement, the Company agreed to provide $100 million of tax-deductible funding by April 30, 2003 (which it funded in March 2003), and an additional $209 million, on a tax-deductible basis, by December 31, 2011. The Company will earn a rate of return of at least 6.60 percent on any portion of the $209 million that it funds before December 31, 2011, plus 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent. This settlement resolves all PSC Staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.

See Item 8. Financial Statements and Supplementary Data - Note I. Commitments and Contingencies, for a detailed discussion of the electric purchase power commitments and the gas supply, storage and pipeline commitments and Note J. Derivatives and Hedging Activities for a detailed discussion of IPP and fossil/hydro swaps and Note E. Long-term Debt for a detailed discussion of mandatory debt repayments.

Capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid USA companies through the money pool or directly. The Company also has the ability to issue first mortgage bonds to the extent that there have been maturities or early redemptions since June 30, 1998. Through March 31, 2003, the Company had $991 million in such first mortgage bond maturities and early redemptions. This is expected to increase to over $1,500 million in 2005 based on scheduled maturities.

On May 1, 2003, the Company completed the restructuring of $414 million of variable rate tax exempt bonds. The bonds are currently in the auction rate mode, which allowed the Company to terminate the $424 million of letter of credit facilities that were in place to provide liquidity support for principal and interest while the bonds were in a variable rate mode.

On May 1, 2003, the Company redeemed early $170 million of First Mortgage Bonds. In addition, on July 7, 2003, the Company plans to redeem early approximately $487 million of Senior Notes. The funds provided for these redemptions have come from available cash within the National Grid USA Money Pool, a long term note issued to National Grid USA, and borrowings from National Grid Transco, parent company of National Grid USA.

New Accounting Standards: In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company has evaluated the impact of this standard on its financial position and results of operations, and the Company does not believe it has any asset retirement obligations that would have a significant impact on its results of operations, cash flows, or financial position.

In April 2003 the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging activities, an amendment of Statement 133” (“FAS 149”). FAS 149 amends and clarifies financial accounting and reporting for derivative instruments and is effective for contracts entered into after June 30, 2003. The Company does not expect the adoption of this statement to have a material effect on its financial position and results of operations.

In May 2003 the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“FAS 150”). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. FAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of FAS 150 on its financial position and results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various market risks because of transactions conducted in the normal course of business. The financial instruments held or issued by the Company are used for investing, financing, hedging or cost control and not for trading.

Quantitative and qualitative disclosures are discussed by market risk exposure category:

Interest Rate Risk
Commodity Price Risk
Equity Price Risk

An Exposure Management Committee (“EMC”) was set up to monitor and control efforts to manage these risks. The EMC issues and oversees the Financial Risk Management Policy (the “Policy”) that outlines the parameters within which corporate managers are to engage in, manage, and report on various areas of risk exposure. At the core of the Policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and in volumes consistent with its core business of delivering electricity and natural gas. The policies of the Company may be revised as its primary markets continue to change, principally as increased competition is introduced and the role of the Company in these markets evolves.

Interest Rate Risk. The Company maintains long-term debt at fixed interest rates and other long-term debt and intercompany short-term debt at variable rates. A controlling factor on the exposure to interest rate variations is the mix of fixed to variable rate instruments maintained by Niagara Mohawk. For March 31, 2003 and 2002, adjustable rate instruments comprise 8.8 percent and 10.5 percent of total capitalization. For the same periods, adjustable rate promissory notes are 9.1 percent and 8.8 percent of total long-term debt. The proportion of adjustable instruments to total capitalization decreased because of the reduction in borrowings from the money pool. In the aggregate at March 31, 2003 and 2002 variable rate instruments do not constitute a significant portion of total capitalization and debt thus, limiting Niagara Mohawk’s exposure to interest rate fluctuations.

If interest rates increased 1 percent next fiscal year, Niagara Mohawk’s interest expense would increase by approximately $6.1 million. This figure was derived by applying a hypothetical 1 percent variance to the variable rate debt of $413.8 million plus the short-term variable borrowings of $198 million at March 31, 2003.

The interest rates on short term borrowings are tied to the published, 30 day, commercial paper rate with the interest rate associated with the amount borrowed from National Grid adjusted monthly.

Commodity Price Risk. The Company is exposed to commodity market price fluctuations in two basic areas: (1) the cost of electricity and natural gas for resale to its customers, and (2) the impact that natural gas, electricity and oil prices have on the swap contracts and one large non-MRA IPP contract. For both gas and electricity, the Company reconciles and recovers commodity costs currently in rates to its customers who purchase the commodity.

The Company takes positions in order to mitigate expected price volatility but only to the extent that quantities are based on expectations of delivery. The Company attempts to mitigate its customers’ exposure to price volatility through a program that hedges risks as appropriate. The Company does not speculate on movements in the underlying prices for these commodities. Commodity purchases are based on analyses performed in relation to expected customer deliveries for electricity and natural gas. The volume of commodities covered by hedging contracts does not exceed amounts needed for customer consumption in the normal course of business or to offset adverse price movements in the contracts being hedged.

As part of the 1998 MRA, the Company entered into restated indexed swap contracts with eight IPPs. The company also entered into financial swap agreements associated with the sales of the Huntley, Dunkirk, and Albany generating stations. The costs of these contracts are fully recovered from customers under the Company’s rate plan. See Item 8. Financial Statements and Supplementary Data - Note J. Derivatives and Hedging Activity, for a more detailed discussion of these swap contracts.

The fair value of the liability under the swap contracts is based upon the difference between projected future market prices and projected contract prices applied to the notional quantities and discounted to the present value. This liability was approximately $793.0, and $653.9 at March 31, 2003 and 2002, respectively and is recorded on the Company’s balance sheets as a “Liability for swap contracts.” The increase is primarily due to a lowering of the discount rate plus a revaluation of the contracts indicating higher forecasted contract prices. These increases were somewhat offset by normal contract settlements. The discount rate is a market-based rate representing the yield curve through the life of the contracts. Based upon the PSC’s approval of the restated contracts, including the indexed swap contracts, as part of the MRA and being provided a reasonable opportunity to recover the estimated indexed swap liability from customers, the Company has recorded a corresponding regulatory asset. The amounts of the recorded liability and regulatory asset are sensitive to changes in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based.

If the indexed contract price were to increase or decrease by 1 percent, the Company would see a $16.4 million increase or decrease in the present value of the projected over-market exposure. If the market prices were to increase or fall by 1 percent, the Company would see a $7.7 million decrease or increase in the projected over-market exposure. If the discount rate were one half percent higher or lower, the net present value of the projected over market exposure would decrease or increase by approximately $9.7 million.

The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed swaps and the Albany swap (Huntley and Dunkirk have fixed contract prices) and a non-MRA IPP where payments are based on gas prices. The contract payments under the IPP and Albany swaps and the non-MRA IPP are indexed to the costs of fuel, primarily natural gas; Albany can be oil or gas. As fuel costs rise, the payments the Company pays under those contracts increase. The current rate plan allows the pass-through of the commodity cost of power to customers; however, the Company uses certain financial instruments to limit the impact of commodity fluctuations on these payments.

The Company has taken steps to mitigate the potential impact that fuel prices would have on the payments for the IPP and Albany swaps, and a physical power contract with a non-MRA IPP. To limit this exposure, the Company purchased NYMEX gas futures contracts and entered into fixed-for-floating swaps on gas basis costs. To hedge the non-MRA IPP contract, the Company purchased NYMEX gas futures. See Item 8. Financial Statements and Supplementary Data - Note J. Derivatives and Hedging Activity for a more detailed discussion of these contracts.

Even with the regulatory recovery of the cost of these contracts, the Company believes it is prudent to hedge these payments. For the period ended March 31, 2003, gas futures were purchased to hedge approximately 100 percent of the amount needed to offset gas price changes.

At March 31, 2002, the Company did not have any open NYMEX futures or basis swaps for this purpose. At March 31, 2003, the open NYMEX futures the Company had in place to hedge the payments under these contracts had a fair value gain of $14.2 million.

Activity for the fair value of the NYMEX futures and gas basis swaps for the 12 months ended March 31, 2003, is as follows:

(in thousands of dths and dollars)	*Hedges of IPP Swaps*				*Hedges Non-MRA IPP*
	NYMEX Futures		Gas Basis Swaps		NYMEX Futures
	Dth	Fair Value	Dth	Fair Value	Dth	Fair Value
March 31, 2002 Asset / (Liability)	-	-	-	-	-	-
New Contracts	58,200.0	-	3,264.3		4,900.0
Settled during period	(37,300.0)	$ (29,732.3)	(3,264.3)	$ (218.5)	(3,200.0)	$ (2,673.0)
Mark-to-market Adjustments	-	42,889.7	-	218.5	-	3,742.7
March 31, 2003 Asset / (Liability)	20,900.0	$ 13,157.4	-	$ -	1,700.0	$ 1,069.7

Gas Supply Price Risk: The cost of natural gas sold to customers fluctuates during the year with prices historically most volatile in the winter months. The Company’s gas rate agreement includes a provision for the collection or pass back of increases or decreases in purchased gas costs. The PSC has also issued a Statement of Policy that the Company attempt to reduce the price volatility in the gas commodity portion of customers’ bills. To implement this policy, the Company uses futures, options, and swaps to hedge against gas price fluctuations. The hedging program will be consistent with the Financial Risk Management Policy.

During the reporting period, the Company attempted to hedge approximately 50 percent of its forecasted annual demand for gas through a program using in-ground storage and financial instruments. The hedging program was further refined to skew the hedging program more heavily toward the winter season (November through March). The Company uses a combination of NYMEX gas futures and a program of combination call and put options. Each NYMEX futures or option contract represents 10,000 Dth of gas. At March 31, 2003 the net open position of cash flow hedges for gas supply was a gain of $1.3 million. There were no open futures contracts or options at March 31, 2002.

The following table details the fair value activity for gas cash flow hedges for the 12 months ended March 31, 2003:

(in thousands of dths and dollars)	*Hedges of Gas Supply*
	NYMEX Futures		Call Options		Put Options
	Dth	Fair Value	Dth	Fair Value	Dth	Fair Value
March 31, 2002 Asset / (Liability)	-	-	-	-	-	-
New Contracts	10,790.0		12,820.0	$ 2,757.8	12,770.0	$ (2,752.6)
Settled during the period	(9,000.0)	$ (10,038.6)	(9,130.0)	-	(9,080.0)	-
Mark-to-market Adjustments		10,894.6		(1,486.5)		1,886.3
March 31, 2003 Asset / (Liability)	1,790.0	$ 856.0	3,690.0	$ 1,271.3	3,690.0	$ (866.3)

The above activity coupled with the in-ground storage hedged approximately 50 percent of the Company’s gas needs for the year. The rest of the gas needs are met through market-based purchases that are subject to price fluctuations. All prudently incurred gas supply costs are mitigated by regulatory rate recovery.

The extent to which market price movement would affect the value of the hedges would be matched by an offsetting change in the anticipated gas purchased costs for the quantity of gas hedged. Therefore, for the quantities hedged, variations in market costs would not result in any significant impact on earnings.

Electricity Price Risk: The Company meets the majority of its electric requirements through a series of long-term physical and financial contracts. There are occasions when the Company may project a short position for electricity needed to supply customers. During those periods electricity is purchased at market prices. If certain proscribed risk values are exceeded during a time when the company forecasts a short power situation, the Company may use electric swaps to lock in a price for electricity. The Company did not use electric swaps during the year ended March 31, 2003. In April 2003, the Company began utilizing NYMEX electric swap contracts to hedge electric purchases for the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.

Equity Price Risk. With the sale of the nuclear generating stations on November 7, 2001 and the associated transfer of all decommissioning trust fund assets to the new owners, the Company eliminated its equity price risk in decommissioning funds.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

Reports of Independent Auditors

Consolidated Statements of Operations, Consolidated Statements of Retained Earnings, and Consolidated Statements of Comprehensive Income (Loss) for the year ended March 31, 2003, the 60 day period ended March 31, 2002, the 30 day period ended January 30, 2002, and for the years ended December 31, 2001 and 2000.

Consolidated Balance Sheets at March 31, 2003 and 2002

Consolidated Statements of Cash Flows for the year ended March 31, 2003, the 60 day period ended March 31, 2002, the 30 day period ended January 30, 2002, and the years ended December 31, 2001 and 2000.

Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and retained earnings, of comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2003 and 2002, and the results of their operations and their cash flows for the year ended March 31, 2003 and the sixty day period ended March 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Boston, Massachusetts
May 7, 2003, except for the Legal Matters
section of Note I, as to which the date is May 30, 2003

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:

In our opinion, the accompanying consolidated statements of operations and retained earnings, of comprehensive income (loss) and of cash flows present fairly, in all material respects, the results of operations and cash flows of Niagara Mohawk Power Corporation and its subsidiaries for the thirty day period ended January 30, 2002 and for each of the two years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Boston, Massachusetts
May 14, 2002

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
(In thousands of dollars)
	For the Year	60 Day Period	30 Day Period	Three Months	For the Year Ended
	Ended March 31,	Ended March	Ended January	Ended March	December 31,
	2003	31, 2002	30, 2002	31, 2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Operating revenues:
Electric	$ 3,310,837	$ 539,758	$ 282,931	$ 823,566	$ 3,393,212	$ 3,207,447
Gas	708,613	149,947	79,691	356,140	721,501	658,502
	4,019,450	689,705	362,622	1,179,706	4,114,713	3,865,949
Operating expenses:
Electricity purchased	1,594,221	231,721	111,444	291,053	1,304,242	1,144,117
Fuel for electric generation	-	-	-	14,317	37,162	74,340
Gas purchased	393,796	83,477	46,651	249,760	419,324	357,524
Other operation and maintenance	840,367	158,367	116,485	248,196	952,853	888,387
Disallowed nuclear investment costs (Note A)	-	-	-	-	123,000	-
Amortization of stranded costs	149,415	23,533	40,911	91,073	393,136	375,487
Depreciation and amortization	198,253	32,877	16,671	77,768	292,224	311,803
Other taxes	253,207	40,892	20,298	50,403	234,346	283,511
Income taxes	93,277	26,362	4,036	24,368	9,582	(6,201)
	3,522,536	597,229	356,496	1,046,938	3,765,869	3,428,968
Operating income	496,914	92,476	6,126	132,768	348,844	436,981
Other income (deductions)	(1,340)	777	2,349	6,631	72,896	(18,785)
Income before interest charges	495,574	93,253	8,475	139,399	421,740	418,196
Interest:
Interest on long-term debt	318,149	56,567	28,490	97,203	367,291	407,288
Other interest	51,554	6,040	926	8,186	35,091	38,554
	369,703	62,607	29,416	105,389	402,382	445,842
Net income (loss)	$ 125,871	$ 30,646	$ (20,941)	$ 34,010	$ 19,358	$ (27,646)

Consolidated Statements of Retained Earnings
(In thousands of dollars)
	For the Year	60 Day Period	30 Day Period	Three Months	For the Year Ended
	Ended March 31,	Ended March	Ended January	Ended March	December 31,
	2003	31, 2002	30, 2002	31, 2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Retained earnings at beginning of period	$ 29,317	$ 138,492	$ 167,044	$ 215,696	$ 215,696	$ 320,911
Net income (loss)	125,871	30,646	(20,941)	34,010	19,358	(27,646)
Purchase accounting adjustment	-	(138,492)	-	-	-	-
Call premium on preferred stock	-	(1,329)	-	-	-	-
Dividends on preferred stock	(5,568)	-	(7,611)	(7,758)	(30,850)	(31,437)
Dividend to Niagara Mohawk Holdings, Inc.	(63,914)	-	-	-	(37,160)	(46,132)
Retained earnings at end of period	$ 85,706	$ 29,317	$ 138,492	$ 241,948	$ 167,044	$ 215,696

Consolidated Statements of Comprehensive Income (Loss)
(In thousands of dollars)
	For the Year	60 Day Period	30 Day Period	Three Months
	Ended March 31,	Ended March	Ended January	Ended March	For the year ended December 31,
	2003	31, 2002	30, 2002	31, 2001	2001	2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Net income(loss)	$ 125,871	$ 30,646	$ (20,941)	$ 34,010	$ 19,358	$ (27,646)
Other comprehensive income(loss):
Unrealized gains (losses) on securities (net of
taxes of $758, $(92), $59, $361, $612,
$343, respectively)	(710)	126	(81)	(671)	(857)	(657)
Hedging activity (net of taxes of $(452), $(1,976),
$(800), ($1,950), $3,790,$-, respectively)	600	2,674	1,084	3,621	(5,127)	-
Additional minimum pension liability	-	-	(23,081)	267	(4,202)	(1,649)
Other comprehensive income (loss)	(110)	2,800	(22,078)	3,217	(10,186)	(2,306)
Comprehensive income(loss)	$ 125,761	$ 33,446	$ (43,019)	$ 37,227	$ 9,172	$ (29,952)

The accompanying notes are an integral part of these financial statements.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)


					March 31,	March 31,
ASSETS					2003	2002
					(Successor)	(Successor)
Utility plant, at original cost:
	Electric plant				$ 5,091,435	$ 4,938,709
	Gas plant				1,402,215	1,352,258
	Common Plant				351,987	359,429
	Construction work-in-progress				143,949	180,667
			Total utility plant		6,989,586	6,831,063
	Less: Accumulated depreciation and amortization				2,342,757	2,226,493
			Net utility plant		4,646,829	4,604,570

Goodwill					1,225,742	1,230,763

Other property and investments					94,314	95,785

Current assets:
	Cash and cash equivalents				30,038	9,882
	Restricted cash				25,350	8,082
	Accounts receivable (less reserves of $100,200
		and $61,300, respectively, and includes
		receivables from associated companies of
		$227 and $1,129, respectively)			543,207	534,914
	Notes receivable				73	50,050
	Materials and supplies, at average cost:
		Gas storage			4,795	3,335
		Other			16,401	17,484
	Derivative instruments (Note A and J)				16,354	411
	Prepaid taxes				90,770	17,491
	Current deferred income taxes (Note G)				35,458	49,704
	Other				10,483	5,075
			Total current assets		772,929	696,428

Regulatory and other non-current assets:
	Regulatory assets (Note B):
		Merger rate plan stranded costs			3,213,657	3,300,885
		Swap contracts regulatory asset			793,028	653,949
		Regulatory tax asset			143,765	203,905
		Deferred environmental restoration costs			301,000	297,000
		Pension and postretirement benefit plans			713,779	540,786
		Loss on reacquired debt			48,255	40,132
		Other			242,290	189,959
			Total regulatory assets		5,455,774	5,226,616

	Long-term notes receivable				-	199,822
	Other assets				48,171	47,604
			Total regulatory and other non-current assets		5,503,945	5,474,042

				Total assets	$ 12,243,759	$ 12,101,588

The accompanying notes are an integral part of these financial statements.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
(In thousands of dollars)


					March 31,	March 31,
CAPITALIZATION AND LIABILITIES					2003	2002
					(Successor)	(Successor)
Capitalization:
	Common stockholder's equity:
		Common stock ($1 par value)			$ 187,365	$ 187,365
			Authorized - 250,000,000 shares
			Issued and outstanding - 187,364,863 shares
		Additional paid-in capital			2,621,440	2,722,894
		Accumulated other comprehensive income			16	126
		Retained earnings			85,706	29,317
			Total common stockholder's equity		2,894,527	2,939,702

	Preferred equity (Note D):
		Cumulative preferred stock ($100 par value, optionally redeemable)			42,625	44,756
			Authorized - 3,400,000 shares
			Issued and outstanding - 426,248 and 447,555 shares, respectively
		Cumulative preferred stock ($25 par value, optionally redeemable)			55,655	55,655
			Authorized - 19,600,000 shares
			Issued and outstanding - 1,113,100 shares

	Long-term debt (Note E)				3,453,989	4,146,642
	Long-term debt to affiliates (Note E)				500,000	-

			Total capitalization		6,946,796	7,186,755

Current liabilities:
	Accounts payable (including payables to associated companies
		of $34,029 and $8,890, respectively)			375,767	239,677
	Customers' deposits				25,843	18,918
	Accrued interest				108,927	111,515
	Short-term debt to affiliates (Note F)				198,000	419,000
	Current portion of long-term debt (Note E)				611,652	544,647
	Other				111,904	96,099
		Total current liabilities			1,432,093	1,429,856

Other non-current liabilities:
	Accumulated deferred income taxes (Note G)				1,157,796	1,108,232
	Liability for swap contracts (Note A and J)				793,028	653,949
	Employee pension and other benefits (Note H)				884,204	745,393
	Other				728,842	680,403
		Total other non-current liabilities			3,563,870	3,187,977

Commitments and contingencies (Notes B and I):
	Liability for environmental remediation costs				301,000	297,000

				Total capitalization and liabilities	$ 12,243,759	$ 12,101,588

The accompanying notes are an integral part of these financial statements.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: Niagara Mohawk Power Corporation (the “Company”) is subject to regulation by the New York State Public Service Commission (“PSC”) and the Federal Energy Regulatory Commission (“FERC”) with respect to its rates for service under a methodology that establishes prices based on the Company’s cost. The Company’s accounting policies conform to Generally Accepted Accounting Principles (“GAAP”), including the accounting principles for rate-regulated entities with respect to the Company’s transmission, distribution and gas operations (regulated business), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

The Company’s consolidated financial statements include its accounts as well as those of its wholly owned subsidiaries. Inter-company balances and transactions have been eliminated.

The closing of the merger with National Grid USA (“National Grid”) and the related push down and allocation of the purchase price has had a significant effect on the reported results of the Company. The sale of the Company’s generation assets at various times during 1999 through 2001 has also affected the comparability of the financial statements.

The consolidated statements of cash flows for the Company have been presented to reflect the closings of the sales of the generation assets, such that certain individual line items are net of the effects of the sales.

Acquisition by National Grid: On January 31, 2002, the Company was acquired by National Grid for approximately $3 billion in cash and American Depository Shares in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The Company maintains its name and legal existence and remains a wholly owned subsidiary of Niagara Mohawk Holdings Inc. (“Holdings”) and, indirectly, National Grid.

Change of Fiscal Year: The Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending March 31. The Company made this change in order to align its fiscal year with that of National Grid. The Company’s first new full fiscal year began on April 1, 2002 and ended on March 31, 2003.

Goodwill: The acquisition of the Company was accounted for by the purchase method, the application of which, including the recognition of goodwill, is being recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets”. The Company reviews its goodwill annually for impairment. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.

Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Utility Plant: The cost of additions to utility plant and replacements of retirement units of property are capitalized. Costs include direct material, labor, overhead and AFDC (see below). Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

Allowance for Funds Used During Construction (“AFDC”): The Company capitalizes AFDC in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFDC rates are determined in accordance with FERC and PSC regulations. The AFDC rates in effect at March 31, 2003 and 2002 were 1.50 percent and 8.61 percent, respectively. AFDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Interest charges” and “Other income” sections, respectively, in the Company’s Consolidated Statements of Operations. The amounts of AFDC credits were recorded as follows:

		60 Day Period	30 Day Period	Three Months
	Year Ended	Ended	Ended	Ended	Year Ended
	March 31,	March 31,	January 30,	March 31,	December 31,
	2003	2002	2002	2001	2001	2000
($'s in 000's)	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)
				(Unaudited)
Other income	$ 187	$ 167	$ 136	$ 798	$ 2,296	$ 2,450
Interest charges	384	180	173	906	2,728	3,161

The above amounts include capitalized interest for generation of $0.8 million and $1.7 million for calendar years ending December 31, 2001 and 2000, respectively. There was no capitalized interest for generation in 2003 and 2002.

Depreciation: For accounting and regulatory purposes, the Company’s depreciation is computed on the straight-line basis using the average service lives for all other classes. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary.

The weighted average service life, in years, for each asset category is presented in the table below:

		60 Day Period	30 Day Period	Three Months
	Year Ended	Ended	Ended	Ended
	March 31,	March 31,	January 30,	March 31,		Year Ended December 31,
	2003	2002	2002	2001	2001		2000
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)		(Predecessor)
Asset Category				(Unaudited)

Electric	34	34	33	34	26		28
Gas	42	41	40	41	43		40
Common	17	16	16	16	17		17

Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The unbilled revenues included in accounts receivable at both March 31, 2003 and 2002 was approximately $132 million.

In accordance with the Merger Rate Plan, the Company recognizes changes in accrued unbilled electric revenues in its results of operations. Pursuant to the Company’s 2000 multi-year gas settlement (ending December 2004), changes in accrued unbilled gas revenues are deferred. At March 31, 2003 and 2002, approximately $6 and $13 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The Company cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.

On August 29, 2001, the PSC approved certain rate plan changes. The changes allowed for certain commodity-related costs to be passed through to customers beginning September 1, 2001. At the same time, a transmission revenue adjustment mechanism was implemented which reconciles actual and rate forecast transmission revenues for pass-back to or recovery from customers. The commodity adjustment clause and the transmission revenue adjustment mechanism continue to remain in effect under the Merger Rate Plan which became effective upon the closing of the merger on January 31, 2002.

The PSC approved a multi-year gas rate settlement agreement (ending December 2004) on July 19, 2000 that includes a provision for the continuation of a full gas cost collection mechanism, effective August 1, 2000. This gas cost collection mechanism was originally reinstated in an interim agreement that became effective November 1, 1999. Such gas cost collection mechanism continues under the Merger Rate Plan. The Company's gas cost collection mechanism provides for the collection or pass back of increases or decreases in purchased gas costs.

Federal and State Income Taxes: As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules. Deferred investment tax credits are amortized over the useful life of the underlying property. Deferred investment tax credits related to the generation assets that were sold were taken into income in accordance with IRS rules. Regulated federal and state income taxes are recorded under the provisions of SFAS No. 109. Tax returns for Holdings and its U.S. subsidiaries were filed within National Grid’s consolidated federal tax returns for the periods subsequent to the closing of the merger. Under the National Grid intercompany tax allocation agreement, Holdings and its subsidiaries are allocated federal tax liability based on their separate company liabilities with adjustment for tax benefits associated with any National Grid holding company losses not attributable to acquisition indebtedness. Holdings and its New York State business subsidiaries will continue to file a combined New York State tax return.

Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs amounted to $62 million and $6 million for the year ended March 31, 2003 and the 60 day period ended March 31, 2002, respectively.

Cash and Cash Equivalents: The Company considers all highly liquid investments, purchased with an original maturity of three months or less, to be cash equivalents.

Derivatives: The Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, on January 1, 2001. Upon implementation, the Company designated several financial instruments as derivatives and qualified certain of these instruments as hedges. Those derivative instruments that did not qualify for hedge accounting were the result of regulatory rulings and therefore, the earnings impact of the adoption of SFAS No. 133 was offset by regulatory assets or liabilities as directed by SFAS No. 71. The result was no impact on earnings for the adoption of SFAS No. 133 by the Company. For further discussion of derivatives, see Note J. Derivatives and Hedging Activity.

Sale of Customer Receivables: The Company has established a single-purpose financing subsidiary, NM Receivables LLC (“NMR”), to purchase and resell a financial interest in a pool of the Company customer receivables. See Note I. Commitments and Contingencies for a complete description of the operations of NMR. The Company adopted SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities - a replacement of Financial Accounting Standards Board (“FASB”) Statement 125” in 2001. The Company’s program for selling its accounts receivable meets the requirements outlined in SFAS No. 140 for recognition and accounting as a sale transaction. As a result, the adoption of this new standard did not have an impact on the reported financial information of the Company.

Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other components of comprehensive income (loss) relate to additional minimum pension liability recognition, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale.

Disallowed Nuclear Investment Costs: In 2001, as part of the PSC order approving the sale of the Company’s nuclear assets, the Company wrote-off $123 million of its nuclear investment.

New Accounting Standards: In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“FAS 143”). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002. The Company has evaluated the impact of this standard on its financial position and results of operations. Based on this evaluation the Company does not believe it has any asset retirement obligations that would have a significant impact on its results of operations, cash flows, or financial position.

In April 2003 the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging activities, an amendment of Statement 133” (“FAS 149”). FAS 149 amends and clarifies financial accounting and reporting for derivative instruments and is effective for contracts entered into after June 30, 2003. The Company does not expect the adoption of this statement to have a material effect on its financial position and results of operations.

In May 2003 the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“FAS 150”). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. FAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently evaluating the impact of FAS 150 on its financial position and results of operations.

Reclassifications: Certain amounts from prior years have been reclassified on the accompanying Consolidated Financial Statements to conform to the 2003 presentation.

NOTE B – RATE AND REGULATORY ISSUES

The Company’s financial statements conform to GAAP, including the accounting principles for rate-regulated entities with respect to its regulated operations. Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5.5 billion at March 31, 2003. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (“CTCs”), and assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company’s remaining electric business (electric transmission and distribution business) continues to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply SFAS No. 71 to these businesses. Also, the Company’s Independent Power Producer (“IPP”) contracts, and the Purchase Power Agreements (“PPAs”) entered into in connection with the generation divestiture, continue to be the obligations of the regulated business.

In the event the Company determines, as a result of lower than expected revenues and/or higher than expected costs, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.

Under the Merger Rate Plan, the Company is earning a return on all of its regulatory assets.

Merger Rate Plan Stranded Costs: Under the Merger Rate Plan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (“MRA”), the cost of any additional IPP contract buyouts and the deferred loss on the sale of the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any additional IPP contract buyouts. Beginning January 31, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates.

Regulatory Tax Asset: The regulatory tax asset represents the expected future recovery from ratepayers of the tax consequences of temporary differences between the recorded book bases and the tax bases of assets and liabilities. This amount is primarily timing differences related to depreciation. These amounts are recovered and amortized as the related temporary differences reverse.

Loss on Reacquired Debt: The loss on reacquired debt regulatory asset represents the costs to redeem certain long-term debt securities, which were retired prior to maturity. These amounts are amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives.

Other: Included in the other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals, income earned on gas rate sharing mechanisms, the incentive earned on the sale of the fossil and hydro generation assets and certain NYISO costs that were deferred for future recovery.

See Notes H, I, and J for a discussion of regulatory asset accounts "Pensions and postretirement benefits", Deferred environmental restoration costs", and "Swap contracts regulatory asset", respectively.

NOTE C – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

	Unrealized			Total
	Gains and	Minimum		Accumulated
(in 000's)	Losses on	Pension		Other
	Available-for-	Liability	Cash Flow	Comprehensive
	Sale Securites	Adjustment	Hedges	Income (Loss)
December 31, 2001	$ (701)	$ (11,818)	$ (5,126)	$ (17,645)
Purchase accounting adjustments	782	34,899	1,368	37,049
Other comprehensive income (loss):
Unrealized gains (losses) on securities,
net of taxes	45			45
Hedging activity, net of taxes			3,758	3,758
Change in minimum pension liability		(23,081)		(23,081)
March 31, 2002	126	-	-	126
Other comprehensive income (loss):
Unrealized gains (losses) on securities,
net of taxes	(710)			(710)
Hedging activity, net of taxes			600	600
March 31, 2003	$ (584)	$ -	$ 600	$ 16

NOTE D – PREFERRED STOCK

The Company has certain issues of non-participating preferred stock, which provide for redemption at the option of the Company, as shown in the table below. From time to time the Company repurchases shares of its preferred stock when it is approached on behalf of its shareholders.

					Redemption price
	Shares		In 000's		per share
	March 31,	March 31,	March 31,	March 31,	(Before adding
Series	2003	2002	2003	2002	accumulated dividends)
Preferred $100 par value:

3.40%	59,960	64,402	$ 5,996	$ 6,440	$103.50
3.60%	138,199	143,018	13,820	14,302	104.85
3.90%	99,817	102,138	9,982	10,214	106.00
4.10%	55,205	60,721	5,520	6,072	102.00
4.85%	37,228	40,355	3,723	4,036	102.00
5.25%	35,839	36,921	3,584	3,692	102.00

Preferred $25 par value:

Adjustable Rate -
Series D	1,113,100	1,113,100	55,655	55,655	50.00 *

			$ 98,280	$ 100,411

* Not redeemable prior to December 31, 2004.

NOTE E – LONG-TERM DEBT

Long-term debt consisted of the following:

$ in 000's
		March 31,	March 31,		March 31,	March 31,
Series	Due	2003	2002	Series	2003	2002
First Mortgage Bonds:				*Promissory Notes:
5 7/8%	2002	$ -	$ 230,000	2015	$ 100,000	$ 100,000
6 7/8%	2003	85,000	85,000	2023	69,800	69,800
7 3/8%	2003	220,000	220,000	2025	75,000	75,000
8%	2004	232,425	232,425	2026	50,000	50,000
6 5/8%	2005	110,000	110,000	2027	25,760	25,760
9 3/4%	2005	137,981	137,981	2027	93,200	93,200
7 3/4%	2006	275,000	275,000	Note Payable to
*6 5/8%	2013	45,600	45,600	National Grid USA	500,000	-
8 1/2%	2023	-	122,020	Other	8,517	20,443
7 7/8%	2024	170,257	170,257	Unamortized discount	(6,020)	(8,615)
*5.15%	2025	75,000	75,000	Total Long-Term Debt	4,565,641	4,691,289
*7.2%	2029	115,705	115,705	Less long-term debt due
Total First Mortgage				within one year	611,652	544,647
Bonds		1,466,968	1,818,988
					$ 3,953,989	$ 4,146,642
Senior Notes:
7 1/4%	2002	-	302,439
7 3/8%	2003	302,439	302,439
5 3/8%	2004	300,000	300,000
7 5/8%	2005	302,439	302,439
8 7/8%	2007	200,000	200,000
7 3/4%	2008	600,000	600,000
8 1/2%	2010	500,000	500,000
Unamortized discount
on 8 1/2% Senior Note		(22,462)	(60,604)
Total Senior Notes		$ 2,182,416	$ 2,446,713

* Tax-exempt pollution control related issues

Several series of First Mortgage Bonds and Promissory Notes were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (“NYSERDA”). Approximately $414 million of such securities bear interest at a daily adjustable interest rate (with an option to convert to other rates, including a fixed interest rate which would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 1.36 percent for the year ended March 31, 2003, 1.12 percent for the three months ended March 31, 2002, 2.50 percent for 2001, and 4.06 percent for 2000 and are supported by bank direct pay letters of credit. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company’s generation facilities or to refund outstanding tax-exempt bonds and notes (see Note F).

On May 1, 2003, the Company completed the restructuring of $414 million of variable rate tax exempt bonds. The bonds are currently in the auction rate mode, which allowed the Company to terminate the $424 million of letter of credit facilities that were in place to provide liquidity support for principal and interest while the bonds were in a variable rate mode.

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2003, excluding capital leases, in millions, are approximately $612, $533, $550, $279 and $200, respectively. The current portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was approximately $1.0 million and $3.4 million at March 31, 2003 and 2002, respectively. The non-current portion of capital lease obligations is reflected in the other regulatory and other liabilities line item on the Consolidated Balance Sheet and was approximately $6 million and $7 million at March 31, 2003 and 2002, respectively.

At March 31, 2003, the Company's long-term debt had a fair value of approximately $4.4 billion. The fair market value of the Company’s long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company for debt of the same remaining maturity.

Early Extinguishment of Debt

During the year ended March 31, 2003, the three months ended March 31, 2002, and the year ended December 31, 2000, the Company defeased or redeemed approximately $122 million, $119 million, and $95 million, respectively, in long-term debt prior to its scheduled maturity.

On May 1, 2003, the Company redeemed early $170 million of First Mortgage Bonds. The funds provided for this redemption came from available cash within the National Grid USA Money Pool.

Losses resulting from the early redemption of debt are deferred and amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives (see Note B).

NOTE F – BANK CREDIT ARRANGEMENTS

The Company had short-term debt outstanding of $198 million and $419 million at March 31, 2003 and 2002, respectively, from the inter-company money pool. The Company has regulatory approval from the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, to issue up to $1 billion of short-term debt. National Grid USA and certain subsidiaries, including the Company, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.

The Company had a senior bank facility agreement that provided the Company with $424 million for letters of credit with a three-year term. The letter of credit facility provided credit support for the Company’s adjustable rate pollution control revenue bonds issued through the New York State Energy Research and Development Authority, discussed in Note E. At March 31, 2003, the Company had no loans outstanding under the credit facility. Subsequent to March 31, 2003, the Company converted its daily adjustable rate pollution control revenue bond program to an auction rate mode on May 1, 2003 and terminated the letter of credit facility.

NOTE G – FEDERAL, STATE AND FOREIGN INCOME TAXES

Following is a summary of the components of federal and state income tax and a reconciliation between the amount of federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statutory tax rate:

		60 Day Period	30 Day Period	Three Months
	Year Ended	Ended	Ended	Ended
	March 31,	March 31,	January 30,	March 31,	Year Ended December 31,
	2003	2002	2002	2001	2001	2000
In thousands of dollars				(Unaudited)
	(Sucessor)	(Sucessor)	(Predecessor)	(Predecessor)	(Predecessor)

Components of federal, state and
foreign income taxes:

Current tax expense (benefit):
Federal	$ (34,908)	$ (1,672)	$ 10,395	$ 6,519	$ 3,637	$ 17,908
State	14,320	(6,698)	357	430	386	468
	(20,588)	(8,370)	10,752	6,949	4,023	18,376
Deferred tax expense (benefit):
Federal	111,157	24,106	(6,194)	11,108	(84,073)	(26,523)
State	(344)	10,098	(780)	(1,109)	1,178	(5,422)
	110,813	34,204	(6,974)	9,999	(82,895)	(31,945)

Total	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)	$ (13,569)


Total income taxes in the consolidated
statements of operations:
Income taxes charged/
(credited) to operations	$ 93,277	$ 26,362	$ 4,036	$ 24,368	$ 9,582	$ (6,201)
Income taxes credited to
"Other Income (deductions)"	(3,052)	(528)	(258)	(7,420)	(88,454)	(7,368)

Total	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)	$ (13,569)

Reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:

			30 Day Period	Three Months
	Year Ended	60 Day Period	Ended	Ended
	March 31,	March 31,	January 30,	March 31,	Year Ended December 31,
	2003	2002	2002	2001	2001	2000
				(Unaudited)
Computed tax	$ 75,641	$ 19,768	$ (5,883)	$ 17,835	$ (20,830)	$ (14,425)
	(Successor)	(Successor)	(Predecessor)	(Predecessor)	(Predecessor)	(Predecessor)
Increase (reduction) including those attributable to
flow-through of certain tax adjustments:

Depreciation	12,183	3,202	1,493	17,112	18,620	27,366
Cost of removal	(6,730)	(1,139)	(583)	(7,682)	(6,441)	(6,936)
Allowance for funds used
during construction - (a)	642	133	47	(1,527)	(806)	(1,179)
State income taxes	20,174	2,541	1,839	(765)	1,564	(4,954)
Non-deductible Executive
compensation	(9,878)	-	9,878	-	-	-
Accrual to return adjustment	6,934	-	-	-	-	-
Goodwill Adjustments	-	-	(1,953)	-	-	-
Pension settlement amortization	-	-	-	-	-	(758)
Debt premium & mortgage
recording tax	3,196	275	51	661	664	806
Real estate taxes	(9,300)	-	-	-	(414)	(5,860)
Amortization of capital stock	-	-	40	661	548	634
Dividends exclusion - federal
income tax returns	-	(67)	(34)	(486)	(468)	(517)
Provided at other than statutory
rate	(2)	4	(2)	-	(4)	(1,186)
Supplemental Executive
Retirement trust fund	-	-	-	-	-	(446)
Settlement of IRS exams	-	-	-	-	-	(1,852)
Voluntary Early Retirement
Plan	(251)	-	-	-	11,272	-
Allocation Percentage/Annualization	-	-	-	(3,002)	-	-
Subsidiaries		(173)	(96)	(313)	(1,115)	3
Deferred investment tax credit
reversal (b)	(3,029)	(528)	(258)	(7,420)	(86,034)	(6,110)
Other	645	1,818	(761)	1,874	4,572	1,845
	14,584	6,066	9,661	(887)	(58,042)	856
Federal income taxes	$ 90,225	$ 25,834	$ 3,778	$ 16,948	$ (78,872)	$ (13,569)

(a) Includes Carrying Charges (Interest Expense) imposed by the PSC.

(b) Deferred investment tax credits of $79.7 million and $0.8 million related to the generation assets that have been sold have been taken into income in 2001 and 2000, respectively, in accordance with IRS rules.
The deferred tax liabilities (assets) were comprised of the following:

In thousands of dollars	March 31,	March 31,
	2003	2002
	(Successor)	(Successor)
Alternative minimum tax	$ 81,639	$ 96,481
Unbilled revenues	16,890	23,052
Non-utilized NOL carryforward	554,821	607,292
Liability for environmental costs	131,750	126,225
Voluntary early retirement program	199,980	249,150
Other	341,850	286,657
Total deferred tax assets	1,326,930	1,388,857

Depreciation related	(857,711)	(810,180)
Investment tax credit related	(46,075)	(49,115)
Deferred environmental restoration costs	(131,750)	(126,225)
Merger rate plan stranded costs	(1,158,204)	(1,169,525)
Merger fair value pension and OPEB adjustment	(163,890)	(188,856)
Other	(91,638)	(103,484)
Total deferred tax liabilities	(2,449,268)	(2,447,385)

Net accumulated deferred income
tax liability	$ (1,122,338)	$ (1,058,528)

In December 1998, the Company received a ruling from the IRS which provided that the amount of cash and the value of common stock that was paid by the Company to the subject terminated IPP Parties was deductible in 1998 which resulted in the Company not paying any regular federal income taxes for 1998, and further generated a substantial net operating loss for federal income tax purposes. The Company carried back a portion of the unused NOL to the years 1996 and 1997, and also for the years 1988 through 1990, which resulted in federal income tax refunds of $135 million that were received in January 1999. As a result of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid General Partnership (the parent company, through an intermediary entity, of National Grid). The Company anticipates that the consolidated tax filing group will be able to utilize the remaining NOL carryforward prior to its expiration in 2019. The amount of the NOL carryforward as of March 31, 2003 is $1.568 billion. National Grid’s ability to utilize the NOL carryforward generated as a result of the MRA and the utilization of alternative minimum tax credits is affected by the rules of Section 382 of the Internal Revenue Code.

NOTE H – PENSION AND OTHER RETIREMENT PLANS

The Company has a non-contributory defined benefit pension plan covering substantially all employees. The plan includes a cash balance benefit in which the participant has an account to which amounts are credited based on qualifying compensation and with interest determined annually based on the average annual 30-year Treasury bond yield. Supplemental non-qualified, non-contributory executive retirement programs provide additional defined pension benefits for certain executives. In addition, the Company provides certain contributory health care and life insurance benefits for active and retired employees and dependents.

The changes in benefit obligations, plan assets and plan funded status for these pension and other retirement plans are summarized as follows:

In thousands of dollars	Pension Benefits		Other Retirement Benefits
	March 31,	March 31,	March 31,	March 31,
	2003	2002	2003	2002
Change in benefit obligation:	(Successor)		(Successor)

Benefit obligation at April 1	$ 1,231,149	$ 1,246,620	$ 743,289	$ 651,423
Service cost	24,970	7,752	6,745	2,412
Interest cost	83,493	22,453	55,551	12,599
Benefits paid to participants	(53,049)	(49,100)	(56,753)	(11,402)
Plan amendments	12,150	-	-	15,012
Curtailments	-	-	-	-
Settlements	(172,427)	(79,165)	-	-
Actuarial (gain) loss	173,522	12,915	183,764	64,674
Dispositions	(3,148)
Special Termination Benefits	-	69,674		8,571
Benefit obligation at end of period	1,296,660	1,231,149	932,596	743,289

Change in plan assets:

Fair value of plan assets at April 1	988,535	1,076,277	276,870	268,740
Contributions	97,794	23,404	81,175	-
Net return on plan assets	(120,801)	2,500	(27,296)	8,130
Benefits paid to participants	(53,049)	(49,100)	-	-
Dispositions	(2,459)
Settlements	(172,427)	(64,546)	-	-
Fair value of plan assets at end of period	737,593	988,535	330,749	276,870

Reconciliation of accrued cost at
end of period:
Funded status	(559,067)	(242,614)	(601,847)	(466,419)
Unrecognized prior service cost	12,150	-		-
Unrecognized net (gain) loss	324,931	(9,631)	208,454	(26,729)
Net amount recognized at end of period	$ (221,986)	$ (252,245)	$ (393,393)	$ (493,148)

Amounts recognized on the consolidated
balance sheets consist of:

Employee pension and other benefits liability	$ (490,811)	$ (252,245)	$ (393,393)	$ (493,148)
Intangible asset	12,150
Regulatory asset	256,675
Net amount recognized at end of period	$ (221,986)	$ (252,245)	$ (393,393)	$ (493,148)

The Dispositions noted in the table above relate to the spin-off of the assets and liabilities in conjunction with the sale of NM Energy.

As part of the acquisition by National Grid, the Company made certain change-of-control payments under the supplemental non-qualified executive retirement program and offered a voluntary early retirement program (“VERP”) to selected employees in areas targeted for staffing reductions. These items appear in the tables as Special Termination Benefits.

At the time of the merger with National Grid, the Company revalued its assets and liabilities to their fair value in accordance with purchase accounting. This revaluation resulted in an increase to the Company’s pension and postretirement benefit plan liabilities in the amount of approximately $440 million, with a corresponding offset to a regulatory asset account, which is being amortized ratably over the ten year period beginning January 31, 2002. The costs of the change-of-control payment under the non-qualified plan were charged to expense. The following table sets forth the components and disposition of payments made in the prior period:

(in millions of dollars)
	Charged to Expense	Deferred in Merger Rate Plan Stranded Cost	Totals
Pension benefits	$ 25.7	$ 44.0	$ 69.7
Other post-retirement benefits		8.6	8.6
	$ 25.7	$ 52.6	$ 78.3

For the year ended March 31, 2003, the Company had a net settlement loss of $29.5 million relating to normal lump-sum distributions and the spin-off of the assets and liabilities related to the sale of NM Energy. For the 60 Day Period ended March 31, 2002, the Company had a net settlement gain of $16.7 million related to the sale of its nuclear assets. In 2001, the Company experienced a net curtailment/settlement loss of $31.9 million due to the employee transfers associated with the sale of the nuclear assets and change of control payments under the supplemental executive retirement plan. Of the 2001 loss, $11.2 million is recorded in the deferred loss on the sale of assets, $6.0 million is due from co-tenants for their allocation of the plant ownership and $14.7 million was charged to expense.

The non-qualified executive pension plan has no plan assets due to the nature of the plan and, therefore, has an accumulated benefit obligation in excess of plan assets of $ 9.2 million, $19.6 million and $17.3 million at March 31, 2003, 2002 and December 31, 2001, respectively.

The following table summarizes the components of the net annual benefit costs.

	In thousands of dollars
	Pension Benefits				Other Postretirement Benefits
		60 Day	30 Day			60 Day	30 Day
	Year	Period	Period		Year	Period	Period
	Ended	Ended	Ended		Ended	Ended	Ended
	March 31,	March 31,	January 30,	December 31,	March 31,	March 31,	January 30,	December 31,
	2003	2002	2002	2001	2003	2002	2002	2001
	(Successor)		(Predecessor)		(Successor)		(Predecessor)
Service cost	$ 24,970	$ 4,886	$ 2,866	$ 32,046	$6,745	$1,348	$1,064	$11,265
Interest cost	83,493	14,637	7,816	88,315	55,551	8,806	3,792	41,664
Expected return
on plan assets	(75,613)	(14,751)	(7,567)	(94,247)	(23,642)	(3,458)	(2,071)	(24,436)
Amortization of the
initial obligation	-	-	191	2,240	-	-	908	10,890
Amortization of
gains and losses	5,559	-	(174)	(1,122)	(498)	-	1,332	7,101
Amortization of prior
service costs	-	-	801	8,464	-	-	302	(7,207)

Net benefit cost before
curtailments and
settlements	38,409	4,772	3,933	35,696	38,156	6,696	5,327	39,277
Curtailment (gain) loss	-	-	-	14,063	-	-	-	3,179
Settlement (gain) loss	29,548	(16,726)	-	14,689	-	-	-	-
Special Termination Benefits		44,000	25,674	-	-	8,571	-	-

Net benefit cost ⁽¹⁾	$ 67,957	$ 32,046	$ 29,607	$ 64,448	$ 38,156	$ 15,267	$ 5,327	$ 42,456

(1) A portion of the benefit costs relates to construction labor, and accordingly, is allocated to construction projects.

		Pension Benefits				Other Retirement Benefits

	March 31,		March 31,	December 31,	March 31,		March 31,	December 31,
	2003		2002	2001	2003		2002	2001
Weighted average assumptions
Discount rate	6.25%		7.50%	7.25%	6.25%		7.50%	7.25%
Expected return on plan assets	8.50		8.75	9.50	8.50		8.50	9.25
Rate of compensation increase
(plus merit increases)	3.25		3.25	2.50	N/A		N/A	N/A
Health care cost trend rate:
2002	N/A		N/A	N/A	N/A		10.00	9.00
2003	N/A		N/A	N/A	10.00		9.00	8.00
2004	N/A		N/A	N/A	9.00		8.00	7.00
2005	N/A		N/A	N/A	8.00		7.00	6.00
2006	N/A		N/A	N/A	7.00		6.00	5.00
2007	N/A		N/A	N/A	6.00		5.00	5.00
2008 and Thereafter	N/A		N/A	N/A	5.00		5.00	5.00

The assumed health cost trend rates decline to five percent in 2008 and remain at that level thereafter. The assumed health cost trend rates can have a significant effect on the amounts reported for the health care plans.

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
	(in thousands of dollars)
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost	$ 6,894	$ (6,140)

Effect on the health care component of
the accumulated postretirement
benefit obligation	$ 91,180	$ (82,943)

Regulatory treatment of pensions and postretirement benefit plans: In addition to the regulatory assets established in connection with purchase accounting and the additional minimum pension liability discussed above, the regulatory asset account “Pension and postretirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and postretirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the $52 million cost of the VERP discussed above, and a postretirement benefit phase-in deferral established in the mid-1990’s. The VERP is being amortized unevenly over the 10 years of the Merger Rate Plan with larger amounts being amortized in the earlier years. VERP amortization in fiscal 2003 was approximately $17 million. The phase-in deferral is being amortized at a rate of approximately $3 million per year.

Additional Minimum Pension Liability: Statement of Financial Accounting Standards No. 87 “Employers’ Accounting for Pensions” states that if a pension plan's accumulated benefit obligation (“ABO”) exceeds the fair value of plan assets, the employer shall recognize in the statement of financial position a liability that is at least equal to the unfunded ABO with an offsetting charge to other comprehensive income. Due to the severe downturn in the capital markets, the Company's ABO at March 31, 2003 is greater than the fair value of plan assets. As such, the Company has recognized an additional minimum pension liability of $269 million on its balance sheet reflecting this underfunded pension obligation. The Company would normally record a charge to other comprehensive income as an offset to this entry. However, due to the nature of its rate plan the Company has not charged other comprehensive income but has instead recorded a regulatory asset. If in the future, capital markets recover such that the fair value of plan assets is once again greater than the ABO, the additional minimum pension liability will be removed from the Company's balance sheets.

Defined Contribution Pension Plan: The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of $8.0 million, $2.2 million and $10.0 million were expensed for the twelve months ended March 31, 2003, the three months ended March 31, 2002, and the year ended December 31, 2001 respectively.

Postemployment Benefits: The Company recognizes the obligation to provide post-employment benefits if the obligation is attributable to employees’ past services, rights to those benefits are identified in the plan documents, payment is probable and the amount of the benefits can be reasonably estimated. At March 31, 2003 and March 31, 2002, the Company’s post-employment benefit obligation is approximately $33.5 million and $23.3 million, respectively.

NOTE I – COMMITMENTS AND CONTINGENCIES

Commodity Reconciliations: As part of the Company's ongoing reconciliation of commodity costs and revenues, the Company has identified several adjustments and included them in filings with the PSC. Specifically, the Company has requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (“NYPA”) hydropower revenues in its commodity adjustment clause, and is proposing to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. In addition, the Company has filed a modification to its tariff and a proposal to refund an additional $7 million associated with the recovery of other NYPA hydropower costs. These filings are pending before the PSC, and the Company cannot predict the outcome of the filings.

Long-Term Contracts for the Purchase of Electric Power: The Company has several types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March 31, 2003, excluding its commitments with New York Power Authority (“NYPA”), which are shown separately, are summarized in the table below. The Company did not enter into any new agreements in fiscal 2003. Following the table are descriptions of the different types of these long-term contracts. For a detailed discussion of the financial swap agreements that the Company has entered into as part of the MRA and the sale of its generation assets (the sale of the Huntley and Dunkirk coal-fired generation plants and the sale of the Albany oil and gas-fired generation plant) which are not included in the table below, see Note J. Derivatives and Hedging Activity.

	(In thousands of dollars)
	Estimated	Estimated		Estimated		Estimated
Fiscal Year	Fixed Costs	Variable Costs		Purchased		Purchased
Ended		Capacity,		Capacity		Energy
March 31,	Capacity	Energy and Taxes **	Total	(in MW)		(in MWh)

2004	$32,286	$516,428	$548,714	3,255		12,006,579
2005	17,397	465,687	483,084	2,033		10,834,411
2006	15,207	382,243	397,450	1,406		8,815,387
2007	15,337	389,079	404,416	1,402		9,403,215
2008	14,836	371,665	386,501	1,385		8,757,187
2009-2017	44,736	1,823,906	1,868,642	674	*	34,165,526

∗ MW value represents the average annual quantity of purchased capacity

∗∗ Does not include puts (see below)

PURPA Contracts
Under the requirements of the Public Utilities Regulatory Policies Act of 1978, as amended (“PURPA”), the Company is required to purchase power generated by IPPs, as defined therein. The Company has 104 PPAs with 112 IPP facilities, amounting to approximately 505 MW of capacity at March 31, 2003. All of this capacity amount is considered firm and excludes PPAs that provide energy only. The table above includes the estimated payments for fixed costs (capacity) and variable costs (capacity, energy and related taxes) that the Company estimates it will be obligated to make under these 104 IPP contracts, excluding the put contracts (see below) and the financial obligation under the swap contracts. The payments to the IPPs are subject to the tested capacity and availability of the facilities, scheduling and price escalation. These payments have been significantly reduced by the consummation of the MRA and additional IPP restructurings made in 1999 and 2000.

Fixed capacity costs (in the table above) relate to three contracts as follows: 1) a contract with an IPP, 2) a contract entered into along with the sale of the Oswego generation assets as discussed further below, and 3) the contract entered into along with the sale of the hydroelectric generation assets as discussed further below. With respect to the IPP contract, the Company is required to make capacity payments, including payments when the facility is not operating but available for service. The terms of this contract allow the Company to schedule energy deliveries and then pay for the energy delivered. Contracts relating to the remaining IPP facilities in service at March 31, 2003 require the Company to pay only when energy is delivered. The Company paid approximately $266 million, $90 million, $321 million, and $416 million in the year ended March 31, 2003, the three months ended March 31, 2002, and the years end December 31, 2001 and 2000 for 2,389,000 MWh, 671,000 MWh, 3,340,000 MWh, and 5,077,000 MWh, respectively, of electric power under all IPP contracts.

Fossil/Hydro Contracts
As part of the sale of the Company’s fossil and hydro generation assets, the Company entered into PPAs with the buyers of these assets for the purchase of capacity and energy. The hydro PPA calls for the purchase of all energy and capacity through September 2004 at prices that approximate forecasted future market prices. The Company anticipates that the energy and capacity to be purchased under the hydro PPA to be at quantities approximating historical generation levels, subject to the effects of water flow availability. The Oswego PPA is primarily a contract for capacity with a nominal amount of energy at prices above forecasted future market prices. The table above includes the estimated payments for variable costs and quantities (capacity and energy) associated with the PPAs that the Company estimates it will make under these contracts. The Company paid approximately $161 million in the year ended March 31, 2003, $33 million in the three months ended March 31, 2002, $109 million in 2001, and $137 million in 2000 for 3,125 MW, 2,769 MW, 2,945 MW, and 1,948 MW of capacity and 2,749,000 MWh, 677,186 MWh, 2,573,000 MWh, and 3,274,000 MWh of electric power, respectively, under these PPAs.

Nuclear Contracts

The table above includes the estimated payments for variable costs and quantities (capacity and energy) associated with the PPAs entered into with the buyers of the nuclear generation assets. As part of the agreement with Constellation to sell its nuclear generation assets, the Company entered into PPAs to purchase 90 percent of the actual hourly nuclear plant output for its percentage interest of the nuclear plants at what are currently believed to be competitive prices for approximately 8 years (Unit 1) and 10 years (Unit 2). The Company pays only for delivered output from the units. Upon the expiration of the PPA for Unit 2, there is a revenue sharing agreement whereby the Company is entitled to future payments from Constellation over a ten-year period if electric energy and capacity market prices exceed certain amounts during the ten-year sharing period. The Company would not be required to buy energy from Constellation, LLC under the revenue sharing agreement. Purchases under the nuclear PPAs began in November 2001. The Company paid approximately $269 million for 7,390,000 MWh of electric power and 985 MW of capacity in the year ended March 31, 2003, $61 million for 1,946,000 MWh of electric power and 1,086 MW of capacity in the three months ended March 31, 2002, and $38 million for 1,266,072 of electric power and 1,086 MW of capacity in 2001. There were no payments in 2000.

Put Contracts
As a part of the MRA, the Company signed agreements with eight of the IPP Parties whereby the IPP Parties have an option to sell the physical delivery of electric power to the Company at market prices. These agreements would have been in effect until the earlier of the NYISO meeting certain volume and capacity conditions for a consecutive six-month period or until June 2008. Although the volume and capacity conditions have not yet been met in all of the contracts, the Company has negotiated to terminate the requirement to purchase electric power from the eight IPP Parties with put agreements. Accordingly, there is no further obligation to purchase electric power under these contracts and information related to such contracts is not included in the table above. The Company did not pay anything in the year ended March 31, 2003 and the three months ended March 31, 2002, but paid approximately $1 million in 2001 and $46 million in 2000 for 13,844 MWh and 898,037 MWh, respectively, of electric power received as part of these put agreements.

While the PPAs for the fossil/hydro asset sales, which were entered into as an integral part of the generation sales, are above market, they are designed to help the Company meet the objectives of rate reduction and price cap commitments as well as meet expected demand as the “provider of last resort” as outlined in the Power Choice agreement.

At March 31, 2003, the Company had long-term contracts to purchase electric power from the following generation facilities owned by NYPA:

	Expiration	Purchased	Estimated	Estimated
	date of	capacity	annual	annual
Facility	contract	in MW	capacity cost	energy cost

Niagara - hydroelectric
project	2007	934	$ 31,596,000	$ 34,250,000
St. Lawrence - hydroelectric
project	2007	104	1,258,000	3,153,000

		1,038	$ 32,854,000	$ 37,403,000

The purchase capacities shown above are based on the contracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges. The total cost of purchases under these contracts, plus other miscellaneous NYPA purchases, was approximately, in millions, $134, $35, $141, and $144 for the year ended March 31, 2003, the three months ended March 31, 2002, and the calendar years 2001 and 2000, respectively. The Company continues to have a contract with NYPA’s Fitzpatrick nuclear facility to purchase for resale up to 46 MW of power for NYPA’s economic development customers.

In addition to the contractual commitments described above, the Company entered into a four-year contract, expiring in June 2003, that gives it the option to buy additional power at market prices from the Huntley coal-fired generation plant, now owned by a new owner. If the Company needs any additional energy to meet its load it can purchase the electricity from other IPPs, other utilities, other energy merchants or through the NYISO at market prices.

Gas Supply, Storage and Pipeline Commitments: In connection with its regulated gas business, the Company has long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines.

The table below sets forth the Company’s estimated commitments at March 31, 2003, for the next five years, and thereafter.

Fiscal Year	(In thousands of dollars)
Ended		Gas Storage/
March 31,	Gas Supply	Pipeline

2004	$130,820	$61,562
2005	71,030	61,562
2006	71,030	9,314
2007	63,456	5,913
2008	-	5,913
2009-2013	-	22,417

With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration for the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity commitments’ amounts are based upon volumes specified in the contracts, and represent demand charges priced at current filed tariffs. At March 31, 2003, the Company’s firm gas supply commitments extend through October 2006, while the gas storage and transportation commitments extend through October 2012.

Sale of Customer Receivables: The Company has established a single-purpose, financing subsidiary, NM Receivables LLC (“NMR”), whose business consists of the purchase and resale of an undivided interest in a designated pool of the Company customer receivables, including accrued unbilled revenues. For receivables sold, the Company has retained collection and administrative responsibilities as agent for the purchaser. As collections reduce previously sold undivided interests, new receivables are customarily sold. NMR has its own separate creditors which, upon liquidation of NMR, will be entitled to be satisfied out of its assets prior to any value becoming available to the Company. The sale of receivables are in fee simple for a reasonably equivalent value and are not secured loans. Some receivables have been contributed in the form of a capital contribution to NMR in fee simple for reasonably equivalent value, and all receivables transferred to NMR are assets owned by NMR in fee simple and are not available to pay the Company’s creditors.

At March 31, 2003 and 2002, receivables of $25 million and $0, respectively, had been sold by NMR to a third party. The undivided interest in the designated pool of receivables is sold with limited recourse. The agreement provides for a formula based loss reserve pursuant to which additional customer receivables are assigned to the purchaser to protect against bad debts.

To the extent actual loss experience of the pool receivables exceeds the loss reserve, the purchaser absorbs the excess. Concentrations of credit risk to the purchaser with respect to accounts receivable are limited due to the Company’s large, diverse customer base within its service territory. The Company generally does not require collateral (i.e. customer deposits).

Environmental Contingencies: The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state, and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to investigate and remediate, as necessary, to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state, or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary.

The Company is currently aware of 117 sites with which it may be associated, including 60, which are the Company-owned. With respect to non-owned sites, the Company may be required to contribute some proportionate share of remedial costs. Although one party can, as a matter of law, be held liable for all of the remedial costs at a site, regardless of fault, in practice costs are usually allocated among Potentially Responsible Parties (“PRPs”). The Company has denied any responsibility at certain of these PRP sites and is contesting liability accordingly. At non-owned manufactured gas plant sites, the Company may bear full or partial responsibility for remedial costs.

Investigations at each of the Company-owned sites are designed to (1) determine if environmental contamination problems exist; (2) if necessary, determine the appropriate remedial actions; and (3) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties will be initiated where appropriate. As site investigations are completed, the Company expects to determine site-specific remedial actions and to estimate the attendant costs for restoration. However, since investigations and regulatory reviews are ongoing for most sites, the estimated cost of remedial action is subject to change.

Estimates of the cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants, location, size and use of the site, proximity to sensitive resources, status of regulatory investigation, and knowledge of activities at similarly situated sites. Actual expenditures are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company’s share of responsibility for such costs, as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several.

As a consequence of site characterizations and assessments completed to date and negotiations with other PRPs or with the appropriate environmental regulatory agency, the Company has accrued a liability in the amount of $301 million, which is reflected in the Company’s Consolidated Balance Sheets at March 31, 2003. The potential high end of the range is presently estimated at approximately $530 million.

The Company determines site liabilities through feasibility studies or engineering estimates, the Company’s estimated share of a PRP allocation, or, where no better estimate is available, the low end of a range of possible outcomes is used. In response to an October 1999 request for information, the Company informed the New York Department of Environmental Conservation (“DEC”) of 24 additional former manufactured gas plant sites that it may be associated with, including three sites that are currently owned by the Company. The Company has executed a voluntary clean-up order with the DEC for the investigation and, as required, the remediation of these additional sites. The Company has included amounts for the investigation and long term monitoring of these sites in the estimated liability. The Company is currently unable to estimate the costs to remediate these additional sites, since they primarily relate to non-owned sites that have been owned and operated by other parties, as well as by some former manufactured gas plant-related predecessor companies of the Company, and because they have not been subjected to site investigations.

The Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations to be recovered from ratepayers. The Merger Rate Plan provides for the continued application of deferral accounting for variations in spending from amounts provided in rates. As a result, the Company does not believe that site investigation and remediation costs will have a material adverse effect on its results of operations or financial condition.

Nuclear Contingencies: As of March 31, 2003, the Company has a liability of $142 million in other regulatory and other liabilities for the disposal of nuclear fuel irradiated prior to 1983. In January 1983, the Nuclear Waste Policy Act of 1982 (the “Nuclear Waste Act”) established a cost of $.001 per KWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the U.S. Department of Energy (“DOE”) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation, who purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.

Plant Expenditures: The Company’s utility plant expenditures are estimated to be approximately $297 million in fiscal 2004. At March 31, 2003, substantial commitments had been made relative to future planned expenditures.

Legal matters:
Alliance for Municipal Power v. New York State Public Service Commission
On February 17, 2003, the Alliance for Municipal Power (“AMP”) filed with the New York state court a petition for review of decisions by the New York State Public Service Commission (the “PSC”) that maintain the PSC’s established policy of using average distribution rates when calculating the exit fees that may be charged to municipalities that seek to leave the Niagara Mohawk system and establish their own municipal light departments. Changes in the methodology for the calculation of the exit fee are not likely to have a material effect on Niagara Mohawk’s financial statements. However, AMP’s petition for review also challenges the lawfulness of Niagara Mohawk’s collection of exit fees from departing municipalities, regardless of the methodology used to calculate those fees. If the court were to rule that Niagara Mohawk is not authorized to collect exit fees, and if the AMP communities proceeded with their plans to municipalize power, the Company could experience a significant shortfall of revenue. In addition, such a ruling could encourage other municipalities to consider municipalizing. The Company would seek to defer any lost revenue for eventual recovery from its remaining customers pursuant to the terms of its rate plan. Niagara Mohawk believes that it has strong defenses to AMP’s petition and is contesting the petition vigorously.

New York State v. Niagara Mohawk Power Corp. et al.
On January 10, 2002, New York State filed a civil action against the Company and NRG in federal district court in Buffalo, New York, for alleged violations of the federal Clean Air Act and related state environmental laws at the Dunkirk and Huntley power plants, which the Company sold in 1999 to NRG and its affiliates (collectively, “NRG”). The State alleged, among other things, that between 1982 and 1999, the Company modified the two plants 55 times without obtaining proper preconstruction permits and implementing proper pollution equipment controls. The state sought, among other relief, statutory penalties under the Clean Air Act, which could have a maximum value of $25,000 to $27,500 per day per violation.

The Company and NRG moved to dismiss the complaint on statute of limitations and other grounds in 2002, and on March 27, 2003, the court granted the motions in part, holding that the violations of the Clean Air Act prior to November 1996 were barred by the federal five-year statute of limitations, and that related state statutory violations prior to November 1999 were barred by the state three-year statute of limitations. This eliminated the Company’s potential exposure to statutory daily penalties prior to these dates. At the same time, the court preserved the State’s non-regulatory claims against the Company and dismissed NRG from the suit.

On April 25, 2003, the State filed a motion for leave to amend the complaint to assert new claims against both the Company and NRG for unspecified amounts. Among other things, the state is seeking to reassert daily violations of the Clean Air Act going back to 1982, the time period covered by its original complaint. On May 30, 2003, the Company filed papers in opposition to the State’s petition. Oral argument has been scheduled for July 2, 2003.

Prior to the commencement of the enforcement action, on July 13, 2001, the Company filed a declaratory judgment action in New York State court in Syracuse against NRG seeking a ruling that NRG is responsible for the costs of pollution controls and mitigation that might result from the State’s enforcement action. As a result of NRG’s voluntary bankruptcy petition, filed in New York federal court for bankruptcy on May 14, 2003, the Company’s declaratory judgment action is stayed.

Niagara Mohawk Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C.
The Company is engaged in collections litigation to recover bills for station service rendered to the owners of three power plants (the “Plants”), which the Company sold in 1999 to three affiliates of NRG: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C. (collectively, the “Defendants”). According to the Company’s records, as of March 31, 2003, the Defendants owed the Company approximately $33 million. After suit was filed, the parties agreed to stay the litigation to permit the FERC to try to resolve the dispute.

As noted above, NRG, the parent company to the Defendants, filed a voluntary bankruptcy petition in New York federal court for bankruptcy on May 14, 2003. The Company intends to seek approval from the bankruptcy court to move forward in its FERC proceeding. Any FERC decision would determine the Company’s ability to charge the Defendants for station service electricity post-bankruptcy, but the collection of the outstanding station service bills as of the bankruptcy filing date will be governed by the bankruptcy court proceedings.

NOTE J – DERIVATIVES AND HEDGING ACTIVITY

In the normal course of business, the Company is party to derivative financial instruments (derivatives) including indexed swap contracts, gas futures, call and put options, electricity swaps, and gas basis swaps that are principally used to manage commodity price risk associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall financial risk-management policy. At the core of the policy is a condition that the Company will engage in risk management activities using commodity and financial markets only when it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. The Company adopted effective January 1, 2001, Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires derivatives to be reported at fair value as assets and liabilities on the balance sheet.
The Company has eight indexed swap contracts, expiring in June 2008 that resulted from the Master Restructuring Agreement (“MRA”), and three swap contracts, expiring in June and September 2003, from the sale of the Company’s Huntley, Dunkirk and Albany electric generating stations. These derivatives are not designated as hedging instruments and are covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2003 and 2002, the Company has recorded liabilities of $793.0 million and $653.9 million for these swap contracts, respectively, and has recorded regulatory assets of equal value. The asset and liability will be amortized over the remaining term of the swaps as nominal energy quantities are settled; however, the value of the unsettled contractual quantities will vary based upon market conditions.

At March 31, 2003, Niagara Mohawk projects that it will make the following payments in connection with its swap contracts for the fiscal years 2004 through 2008 and thereafter, subject to changes in market prices and indexing provisions:

	Projected
	Payment
Year Ended	(in thousands
March 31,	of dollars)

2004	$ 191,920
2005	148,073
2006	150,785
2007	141,311
2008	132,503
Thereafter	28,860
	$ 793,452

The Company uses New York Mercantile Exchange (“NYMEX”) gas futures and gas basis swaps to hedge gas commodity components of its indexed swap contracts. There were no open basis swaps at March 31, 2003 or 2002; however basis swaps were used during the fiscal year. For the twelve months ended March 31, 2003 the basis swaps resulted in a decrease to purchased power expense of $0.2 million. At March 31, 2003, the Company recorded a deferred gain on the futures contracts of $17.3 million, offset by the balance sheet item “Derivative Instruments” for $ 14.2 million with the resulting $3.1 having settled through cash for the hedge month of April 2003. At March 31, 2002 there were no open futures contracts. For the twelve months ended March 31, 2003 settlement of NYMEX futures contracts resulted in a decrease to purchased power expense of $29.3 million.

Consistent with the Company’s commodity price risk management strategy, during the reporting periods the Company purchased NYMEX gas futures and used combination call and put options (collars) that meet the requirements for and are designated as cash flow hedging instruments in accordance with SFAS No. 133. There were no open positions in either NYMEX futures or collars at March 31, 2002. For NYMEX futures at March 31, 2003, the Company has recorded a deferred gain of $0.9 million. The deferred gain was offset by the balance sheet item “Derivative Instruments” for $0.9 million with a minimal amount having settled through “Cash” for the hedge month of April 2003. Call options at March 31, 2003 were in an asset position of $1.3 million with $1.1 million deferred in a regulatory liability and $0.2 million deferred in Accumulated Other Comprehensive Income net of deferred taxes. Put options at March 31, 2003 were in a liability position of $0.9 million with $0.9 million deferred in a regulatory asset and a nominal amount deferred in Accumulated Other Comprehensive Income net of deferred taxes. The gains and losses on the derivative that are deferred and reported in accumulated other comprehensive income will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. For the twelve months ended March 31, 2003, a net decrease of $10.0 million was recorded to gas purchases offset by a corresponding increase in the cost of a comparable amount of gas. The actual amounts to be recorded in earnings are dependent on future changes in the contract values, the majority of these deferred amounts will be reclassified to earnings within the next 12 months. A nominal amount of the hedging instruments extend into April 2004. There were no gains or losses recorded during the year from the discontinuance of gas futures and electricity swap cash flow hedges.

In the twelve months ended March 31, 2002, fixed-for-floating swaps on electricity were utilized and resulted in a credit to purchased power of $0.4 million. None of these instruments were used during the year ended March 31, 2003. There were no open electric swaps at March 31, 2003 or 2002. In April 2003, the Company began utilizing NYMEX electric swap contracts to hedge electric purchases for the summer 2003. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased.

NOTE K – STOCK BASED COMPENSATION

Under Holdings’ stock compensation plans prior to the merger, stock units and stock appreciation rights (“SARs”) were granted to officers, key employees and directors. In addition, Holdings’ plans previously allowed for the grant of stock options to officers. The table below sets forth the activity under Holdings’ stock compensation plans for the years January 1, 2000 through March 31, 2003. On January 31, 2002, the acquisition of Holdings by National Grid was completed.

				Options
				Wtd. Avg.
				Exercise
	SARs*	Units	Options	Price

Outstanding at December 31, 1999	2,852,562	864,994	247,375	$ 17.76
Granted	574,500	647,049	-
Exercised	(44,700)	(478,470)	-
Forfeited	(29,500)	(29,097)	(54,000)	17.94
Outstanding at December 31, 2000	3,352,862	1,004,476	193,375	17.71
Granted	-	662,281	-
Exercised	(190,611)	(336,423)	-
Forfeited	(5,347)	(21,337)	-	-
Outstanding at December 31, 2001	3,156,904	1,308,997	193,375	17.50
Granted	-	-	-
Exercised	(1,438,545)	(1,044,997)	(102,625)
Forfeited	(2,400)	(264,000)	(90,750)	17.50
Outstanding at January 31, 2002	1,715,959	-	-	-
Conversion of Holdings' stock to ADSs	(709,817)
Exercised	(46,257)
Outstanding at March 31, 2002	959,885	-	-	-
Exercised	(207,005)
Outstanding at March 31, 2003	752,880	-	-	-

* Note: The SARs related to Holdings' stock prior to the merger and National Grid Transco
American Depositary Shares subsequent to the merger on January 31, 2002.

The Company's SARs and stock units provided for the acceleration of vesting upon the occurrence of certain events relating to a change in control, merger, sale of assets or liquidation of the Company. On January 31, 2002 outstanding Holdings SARs were converted to National Grid Transco plc (“NGT”) American Depositary Share (“ADS”) SARs. The SARs are payable in cash based on the increase in the ADS price from a specified level. As such, for these awards, compensation expense is recognized based on the value of Holdings’ stock price or NGT’s ADS price over the vesting period of the award. Upon the closing of the merger, the units were paid, and each stock option outstanding was cancelled and entitled the holder to receive an amount in cash.

Included in the Company’s results of operations for year ended March 31, 2003, the three months ended March 31, 2002, and the years ending December 31, 2001 and 2000, is approximately $3 million, $21 million, $12 million, and $11 million, respectively, related to these plans.

Since stock units and SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123 is the same. Therefore, the pro forma disclosure of information regarding net income, as required by SFAS No. 123, related only to Holdings’ outstanding stock options, the effect of which is immaterial to the financial statements for the 30 day period ended January 30, 2002, and the years ended 2001 and 2000. There were no outstanding stock options subsequent to the closing of the merger.

NOTE L – SEGMENTS

The Company’s reportable segments for the year ended March 31, 2003 are electricity-transmission, electricity-distribution, and gas. The Company is engaged principally in the business of purchase, transmission, and distribution of electricity and the purchase, distribution, sale, and transportation of natural gas in New York State. Certain information regarding the Company’s segments is set forth in the following table. General corporate expenses, property common to the various segments, and depreciation of such common property have been allocated to the segments based on labor or plant, using a percentage derived from total labor or plant dollars charged directly to certain operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes, and unamortized debt expense.

For periods prior to the year ended March 31, 2003, the segment data presented is limited to electricity (in total) and gas. Prior to the Company’s merger with National Grid, the electricity segment was managed as a single operating unit, with a single bundled rate structure. Beginning in fiscal 2003, new mechanisms were put in place to capture the separate financial information, including revenue, for electricity-transmission and electricity-distribution in the Company’s detailed accounting records to facilitate the new management approach. These mechanisms were not in place in prior periods. Additionally, prior to fiscal 2003 the Company was also engaged in the operation of electricity generation, further complicating the development of comparable segment information for the prior periods. As a result, presentation of pre-fiscal 2003 information on a basis fully comparable to the fiscal 2003 reportable segments is not possible, and any attempt to develop additional segment data would require undue time and effort in recalculating comparative amounts.

(Successor - in millions of dollars)
			Electric -	Electric -
			Transmission	Distribution	Gas	Corporate	Total

Year ended March 31, 2003
	Operating revenue		$ 248	$ 3,062	$ 709	$ -	$ 4,019
	Operating income before
		income taxes	85	437	68	-	590
	Depreciation and amortization		35	127	36	-	198
	Amortization of stranded costs		-	149	-	-	149

Goodwill
	Goodwill, at March 31, 2002		$ 304	$ 712	$ 215	$ -	$ 1,231
	Decrease in goodwill		(1)	(3)	(1)	-	(5)
	Goodwill, at March 31, 2003		$ 303	$ 709	$ 214	$ -	$ 1,226

March 31, 2003
	Total assets		$ 1,444	$ 8,780	$ 1,576	$ 444	$ 12,244

(Successor - in millions of dollars)
			Electric	Gas	Corporate	Total

60 Day Period ended March 31, 2002
	Operating revenue		$ 540	$ 150	$ -	$ 690
	Operating income before
		income taxes	95	24	-	119
	Depreciation and amortization		27	6	-	33
	Amortization of Stranded Costs		24	-	-	24

March 31, 2002
	Total assets		$ 10,271	$ 1,422	$ 409	$ 12,102


(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

30 Day Period ended January 30, 2002
	Operating revenue		$ 283	$ 80	$ -	$ 363
	Operating income before
		income taxes	3	7	-	10
	Depreciation and amortization		14	3	-	17
	Amortization of Stranded Costs		41	-	-	41

(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

Three Months Ended March 31, 2001 (Unaudited)
	Operating revenue		$ 824	$ 356	$ -	$ 1,180
	Operating income before
		income taxes	114	43	-	157
	Depreciation and amortization		69	9	-	78
	Amortization of Stranded Costs		91	-	-	91


(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

Year ended December 31, 2001
	Operating revenue		$ 3,393	$ 722	$ -	$ 4,115
	Operating income before
		income taxes	223	135	-	358
	Depreciation and amortization		256	36	-	292
	Amortization of Stranded Costs		393	-	-	393


(Predecessor - in millions of dollars)
			Electric	Gas	Corporate	Total

Year ended December 31, 2000
	Operating revenue		$ 3,207	$ 659	$ -	$ 3,866
	Operating income before
		income taxes	358	73	-	431
	Depreciation and amortization		276	36	-	312
	Amortization of Stranded Costs		375	-	-	375

NOTE M – RESTRICTION ON COMMON DIVIDENDS

The indenture securing the Company’s mortgage debt provides that retained earnings shall be reserved and held unavailable for the payment of dividends on common stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25 percent of depreciable property as defined therein. These provisions have never resulted in a restriction of the Company’s retained earnings.

The Company is limited by the Merger Rate Plan and under FERC and Securities and Exchange Commission (“SEC”) orders with respect to the amount of dividends it can make to Holdings. The Company is allowed to make dividends in an amount up to the pre-merger retained earnings balance plus any earnings subsequent to the merger, together with other adjustments that are authorized under the Merger Rate Plan and other regulatory orders.

NOTE N – SUBSEQUENT EVENT

In connection with an audit performed by PSC Staff, the Company has reached a settlement with the Staff that resolves all issues associated with its pension and other postretirement benefit obligations for the period prior to the acquisition of the Company by National Grid. The settlement is subject to approval by the full New York State Public Service Commission. Among other things, the settlement covers the funding of the Company’s pension and post-retirement benefit plans. Under the settlement, the Company agreed to provide $100 million of tax-deductible funding by April 30, 2003 (which it funded in March 2003), and an additional $209 million, on a tax-deductible basis, by December 31, 2011. The Company will earn a rate of return of at least 6.60 percent on any portion of the $209 million that it funds before December 31, 2011, plus 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent. This settlement resolves all PSC Staff audit issues related to the pre-acquisition period with the exception of certain gas deferrals and a Staff review of a pending Company compliance filing related to the sale of the Nine Mile Nuclear Station.

NOTE O – QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating revenues, operating income, and net income (loss) by quarter from April 1, 2001 through March 31, 2003 are shown in the following table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter.

		In thousands of dollars
				Net
		Operating	Operating	Income
Quarter Ended		Revenues	Income	(Loss)
March 31,	2003(a)	$ 1,186,061	$ 133,586	$ 37,650
	2002(b)	1,052,327	98,602	9,705
December 31,	2002(a)	$ 967,807	$ 122,492	$ 37,551
	2001(c)	982,963	97,596	(1,852)
September 30,	2002(a)	$ 954,339	$ 119,264	$ 22,490
	2001(c)	1,007,839	34,736	11,848
June 30,	2002(a)	$ 911,243	$ 121,572	$ 28,180
	2001(c)	944,205	83,744	(24,648)

(a) Successor
(b) Includes both Successor and Predecessor financial data
(c) Predecessor

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

The Company has nothing to report for this item.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table lists the Company’s executive officers and directors:

Name	Age	Position
William F. Edwards	46	President and Director
John G. Cochrane	45	Chief Financial Officer
Gary R. Jesmain	55	Senior Vice President, Business Services
Clement E. Nadeau	51	Senior Vice President, Operations, and Director
Kwong O. Nuey, Jr.	55	Vice President and Director
Anthony C. Pini	50	Senior Vice President, Customer Service, and Director
Steven W.Tasker	45	Vice President
Lawrence J. Reilly	47	General Counsel of National Grid USA
Joseph T. Ash, Jr.	54	Vice President, Gas Delivery
Edward A. Capomacchio	57	Controller
Michael E. Jesanis	46	Director

Directors are elected at the annual meeting of stockholders and hold office until the next annual meeting or a special meeting in lieu thereof, and until their successors are elected and qualified. All of the directors were elected in 2002. There are no family relationships between any of the directors and executive officers listed in the table. There are no arrangements or understandings between any executive officer and any other person pursuant to which he was selected as an officer.

Mr. Edwards was elected President of the Company and Senior Vice President of National Grid USA effective January 31, 2002. Prior to that, he served as Senior Vice President and Chief Financial Officer of the Company from 1997 to 2002. He served as Senior Vice President and Chief Financial Officer of Niagara Mohawk Holdings, Inc. from 1999 to 2002. He also serves as a director of National Grid USA and Utilities Mutual Insurance Company.

Mr. Cochrane was elected Chief Financial Officer effective August 1, 2002. He has served as National Grid USA’s Chief Financial Officer since January 2001 and Senior Vice President since May 2002 and was Treasurer of National Grid USA (and its predecessor, New England Electric System) and of National Grid USA Service Company from 1998 to 2002. Mr. Cochrane was also Treasurer of Massachusetts Electric Company from 1998 to 2000 and of The Narragansett Electric Company from 1993 to 2000.

Mr. Jesmain has served as Senior Vice President, Business Services, since February 2002. From February 1996 to February 2002 he was Regional Manager, Central Region.

Mr. Nadeau was elected Senior Vice President of the Company effective January 31, 2002. Prior to that, he served as Vice President-Electric Delivery beginning in 1998.

Mr. Nuey was elected Vice President and Chief Information Officer of National Grid USA Service Company effective January 31, 2002. He was the Vice President and Controller of National Grid USA Service Company from 2000 to 2002 and the Vice President and Director of Retail Information Services of the Company from 1997-2000.

Mr. Pini was elected Senior Vice President of the Company effective January 31, 2002. Previously, he was President of NEES Communications, Inc. from 1997 to 2002 and Vice President of Retail Customer Service of National Grid USA subsidiaries from 1993 to 1997.

Mr. Tasker has served as Senior Vice President, Distribution Finance, and Treasurer since February 2002. He was Vice President and Controller from December 1998 to February 2002.

Mr. Reilly has been Secretary and General Counsel of National Grid USA since January 2001. Since 2000 he has been National Grid USA Senior Vice President, and he served as President of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company from 1996 to 2000.

Mr. Ash has served as Vice President, Gas Delivery, since December 1998. From January 1996 to December 1998, he was Vice President, Purchasing and Support Services.

Mr. Capomacchio was appointed Controller of the Company and Vice President and Controller of National Grid USA Service Company in January 2002. He has served as Controller of Massachusetts Electric Company, The Narragansett Electric Company, Nantucket Electric Company and Granite State Electric Company since May 2001. Mr. Capomacchio was Assistant Controller of the Service Company from 1998 to 2002.

Mr. Jesanis has served as National Grid USA’s Executive Vice President and Chief Operating Officer of since January 31, 2001. He served as Senior Vice President and Chief Financial Officer of National Grid USA’s predecessor, New England Electric System, from 1998 to 2000 and was its Treasurer from 1992 to 1998. Mr. Jesanis is also a director of National Grid USA and of Niagara Mohawk Holdings, Inc.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers and directors, and persons who own more than 10 percent of a registered class of the Company’s equity securities, to file reports with the Securities and Exchange Commission disclosing their ownership of stock in the Company and changes in such ownership. To the Company’s knowledge, based solely on written representations from reporting persons, no such reports were required to be filed during the year ended March 31, 2003.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation paid or accrued for services rendered to Niagara Mohawk in fiscal year 2003, the transition period from January 1, 2002 to March 31, 2002 and the calendar years 2001 and 2000 by the president and the four most highly paid persons who were serving as executive officers on March 31, 2003 (the “Named Executive Officers”).

Name and Principal Position	Year	Annual Compensation (a)			Long-Term Compensation		All Other Compen- sation ($)(d)
		Salary($)	Bonus($)(b)	Other Annual Compen-sation ($)(c)	Awards
		Salary($)	Bonus($)(b)	Other Annual Compen-sation ($)(c)	Restricted Stock Award(s) ($)	Securities Underlying Options/ SARs(#)
William F. Edwards President	2003 2002 (e) 2001 2000	399,993 99,665 379,994 331,663	224,396 41,141 222,716 142,816	6,010 0 4,785 0	0 0 354,000 425,938	56,206 0 0 25,000	1,823 3,882,601 600,267 80,699
Anthony C. Pini Senior Vice President Customer Service	2003	225,000	137,925	113,562	0	31,616	642
Clement E. Nadeau Senior Vice President Operations	2003	209,997	149,098	8,882	0	29,508	807
Joseph T. Ash, Jr. Vice President Gas Delivery	2003	193,297	76,932	6,911	0	21,723	895
Steven W. Tasker Senior Vice President Distribution Finance	2003 2002 (e) 2001 2000	179,998 43,599 162,656 160,004	86,399 17,412 64,681 49,087	8,281 1,308 1,994 0	0 0 106,200 130,938	20,234 0 0 7,000	296 95 171,198 46,260

(a)	Includes deferred compensation in category and year earned.
(b)	The bonus figure represents cash bonuses and the fair market value of unrestricted securities of National Grid Transco awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program.
(c)	Includes amounts reimbursed for the payment of taxes on certain noncash benefits and contributions to the incentive thrift plan that are not bonus contributions, including related deferred compensation plan match. For Mr. Pini, also includes amounts associated with relocation ($104,161) and a nominal miscellaneous cash award.
(d)	Includes Company contributions to life insurance.
(e)	Information is for the transition period from January 1, 2002 to March 31, 2002.

Option Grants in Last Fiscal Year

The following table shows all stock option grants to the Named Executive Officers during fiscal year 2003.

Individual Grants					Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term
	Number of Securities Underlying Option Granted (#) (a)	Percent of Options Granted to Employees in Fiscal Year (b)	Exercise of Base Price ($/Sh) (c)	Expiration Date	5% ($)	10% ($)
William F. Edwards	56,206	2.7%	$7.117	June 2012	651,587	1,037,544
Anthony C. Pini	31,616	1.5%	$7.117	June 2012	366,519	583,621
Clement E. Nadeau	29,508	1.4%	$7.117	June 2012	342,082	544,708
Joseph T. Ash, Jr.	21,723	1.0%	$7.117	June 2012	251,831	400,999
Steven W. Tasker	20,234	1.0%	$7.117	June 2012	234,570	373,513

(a)	The options are expressed in terms of ordinary shares of National Grid Transco listed on the London Stock Exchange.
(b)	This percentage is in relation to option grants made to all employees of National Grid USA and its subsidiaries.
(c)	The exercise price of $7.117 was converted from 4.815 GBP using a conversion of 1 GBP to $1.478065.

The options vest over time, subject to a performance condition. The options are exercisable only if and to the extent that NGT’s total shareholder return (as defined in the applicable plan) during the three years of the performance period is equal to or better than the median of a specific comparison group. If the performance condition is not met after the three-year period, the National Grid Transco Remuneration Committee may modify the performance condition or methodology on subsequent anniversaries of the performance period, taking into account any factor it deems relevant.

Option/SAR Exercises in Fiscal Year 2003 and Fiscal Year-End Option/SAR Values

The following table sets forth, for the Named Executive Officers, the number of shares for which stock options were exercised in fiscal year 2003, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options held by each at fiscal year-end.

Name	Options Exercised (#)	Value Realized ($)	Number of Securities Underlying Unexercised Options on March 31, 2003 (#)(a)		Value of Unexercised Options on March 31, 2003 ($)(b)
Name	Options Exercised (#)	Value Realized ($)	Exercisable	Unexercisable	Exercisable	Unexercisable
William F. Edwards	0	0	0	56,206	0	0
Anthony C. Pini	0	0	0	91,108	0	0
Clement E. Nadeau	0	0	0	29,508	0	0
Joseph T. Ash, Jr.	0	0	0	21,723	0	0
Steven W. Tasker	0	0	0	20,234	0	0

(a)	The first of the options were to have vested in March 2003 but did not, as the Company did not meet specified performance conditions.
(b)	At March 31, 2003, the price per ordinary share on the London Stock Exchange was lower than the exercise price for any of the Named Executive Officers’ stock options.

The following table sets forth, for the Named Executive Officers, exercises of SARs in fiscal year 2003, the realized value or spread (the difference between the exercise price and market value on the date of exercise) and the number and unrealized spread of the unexercised options and SARs held by each at fiscal year-end.

Name	SARs Exercised (#)	Value Realized ($)	Number of Securities Underlying Unexercised SARs At Fiscal Year-End (#)		Value of Unexercised SARs At FiscalYear-End ($)(a)
Name	SARs Exercised (#)	Value Realized ($)	Exercisable	Unexercisable	Exercisable	Unexercisable
William F. Edwards	0	0	0	0	0	0
Anthony C. Pini	0	0	0	0	0	0
Clement E. Nadeau	5,512	114,668	20,814	0	$175,352	0
Joseph T. Ash, Jr.	0	0	12,312	0	$68,982	0
Steven W. Tasker	1,759	27,212	24,567	0	$239,546	0

(a)

Calculated based on the closing price on March 31, 2003 of National Grid Transco American Depositary Receipts traded on the New York Stock Exchange ($30.75). SAR grants were made under Niagara Mohawk’s Long Term Incentive Plan which was terminated on the merger with National Grid. At that time, outstanding grants of SARs were converted to SARs over NGT American Depositary Shares using a specified exchange ratio.

Pension Plans

Depending on their company origin prior to the merger of the Company with National Grid USA, executives participate in one of two qualified pension plans: the National Grid USA Companies Final Average Pay Pension Plan (“FAPP”) or the Niagara Mohawk Pension Plan (“Basic Plan”). Both FAPP and the Basic Plan are noncontributory, tax-qualified defined benefit plans which provide all employees of the Company with a minimum retirement benefit. Pension benefits are related to compensation, subject to the maximum annual limits noted in the two pension tables below.

Under FAPP, a participant’s retirement benefit is computed using formulas based on percentages of highest average compensation computed over five consecutive years. The compensation covered by FAPP includes salary, bonus and incentive share awards.

Under the Basic Plan, a participant’s retirement benefit is based on one of two formulas depending on age and years of service on July 1, 1998: the cash balance formula, or the highest five-year average compensation. Under the cash balance formula a participant’s retirement benefit grows monthly, according to pay credits (from 4 percent to 8 percent times salary) plus interest credits. A non-represented (management) employee who was at least 45 years of age and had 10 years of service on July 1, 1998 will receive the retirement benefit resulting from the higher of the two formulas.

The Executive Supplemental Retirement Plan (“ESRP”) is a noncontributory, nonqualified defined benefit plan that provides additional retirement benefits to the named executive officers and certain other members of management who are eligible to receive either a FAPP or Basic Plan benefit and whose compensation exceeds legal limits under the applicable plan or who are otherwise selected for participation. Depending on the participant, the ESRP may provide for unreduced benefits payable as early as age 55, may enhance the qualified plan formula, may give credit for more years of service or may award benefits not otherwise payable due to limits on benefits that can be provided under the qualified plan. ESRP participants who formerly participated in the Niagara Mohawk Supplemental Executive Retirement Plan (“Niagara Mohawk SERP”) are entitled to a minimum benefit calculated based on the terms of that plan frozen as of the merger date.

Pension Plan Tables

The following tables show the maximum retirement benefit (adjusted for Social Security, if applicable) an executive officer can earn in aggregate under the applicable qualified plan (FAPP or the Basic Plan) together with the ESRP or the Niagara Mohawk SERP, as applicable. The benefit calculations are made as of March 31, 2003 and assume the officer has selected a straight life annuity commencing at age 65. Annual compensation limits of $200,000 under a tax-qualified plan will reduce the portion payable under the qualified pension plan for some highly compensated officers. The benefits listed are shown without any joint and survivor benefits. If a participant elected a 100 percent joint and survivor benefit at age 65, with a spouse of the same age, the benefit shown in the table would be reduced by approximately 16 percent.

Maximum Pension Benefit – ESRP

Five-Year Average Compensation	Years of Service
Five-Year Average Compensation	10*	15*	20	25	30	35
$100,000	$18,922	$27,383	$35,844	$44,056	$52,267	$57,228
$150,000	$29,922	$43,383	$56,844	$69,931	$83,017	$91,228
$200,000	$40,922	$59,383	$77,844	$95,806	$113,767	$125,228
$250,000	$51,922	$75,383	$98,844	$121,681	$144,517	$159,228
$300,000	$62,922	$91,383	$119,844	$147,556	$175,267	$193,228
$350,000	$73,922	$107,383	$140,844	$173,431	$206,017	$227,228
$400,000	$84,922	$123,383	$161,844	$199,306	$236,767	$261,228
$450,000	$95,922	$139,383	$182,844	$225,181	$267,517	$295,228
$500,000	$106,922	$155,383	$203,844	$251,056	$298,267	$329,228

Maximum Pension Benefit – Niagara Mohawk SERP

Three-Year Average Annual Salary	Years of Service
Three-Year Average Annual Salary	10*	15*	20	25	30	35
$150,000	$ 20,910	$33,615	$ 79,554	$ 79,554	$ 79,554	$ 79,554
250,000	28,160	45,240	139,554	139,554	139,554	139,554
350,000	28,160	45,240	199,554	199,554	199,554	199,554
450,000	28,160	45,240	259,554	259,554	259,554	259,554
550,000	28,160	45,240	319,554	319,554	319,554	319,554
650,000	28,160	45,240	379,554	379,554	379,554	379,554
750,000	28,160	45,240	439,554	439,554	439,554	439,554
850,000	28,160	45,240	499,554	499,554	499,554	499,554
900,000	28,160	45,240	529,554	529,554	529,554	529,554

*Basic Plan benefit only.

For purposes of the pension program, the Named Executive Officers had approximately the following credited years of benefit service as of March 31, 2003: Mr. Edwards, 24 years; Mr. Nadeau, 30 years; Mr. Pini, 24 years; Mr. Ash, 33 years and Mr. Tasker, 15 years. Mr. Edwards received the Niagara Mohawk SERP benefit at the merger with National Grid and is eligible to receive a pension benefit under the ESRP, to be offset by the SERP benefit already received. Mr. Nadeau and Mr. Tasker will receive the higher of the pension benefit paid under the ESRP or that paid under the Niagara Mohawk SERP. Mr. Ash is eligible for the Niagara Mohawk SERP and is not eligible for the ESRP. Mr. Pini is eligible for the ESRP and is not eligible for the Niagara Mohawk SERP.

At retirement, the Named Executive Officers and certain members of management may become eligible for post-retirement health and life insurance benefits determined based on their age and service. The executive may be required to contribute to the cost of benefits, depending on date of hire and total years of service.

Payments on a Change in Control or Termination of Employment

Mr. Edwards has an employment agreement with National Grid USA, which will remain in effect until January 31, 2005. If Mr. Edwards terminates his employment for good reason or National Grid USA terminates his employment without cause, Mr. Edwards will be entitled to a lump sum severance benefit equal to four times his base salary. He will also be entitled to employee benefit plan coverage for medical, prescription drug, dental and hospitalization benefits and payment of premiums for life insurance for the remainder of his life. His coverage under other employee benefit plans will continue for four years. In the event that the severance payments to Mr. Edwards subject him to excise tax on excess parachute payments under the Internal Revenue Code, he would be reimbursed for such excise tax (plus the income tax and excise tax payable on such reimbursement). In the event of a dispute over Mr. Edwards’s rights under the agreement, National Grid USA will pay Mr. Edwards’s reasonable legal fees with respect to the dispute unless Mr. Edwards’s claims are found to be frivolous.

As used in Mr. Edwards’s employment agreement, “good reason” generally means a materially adverse change in duties, reduction in salary or benefits or relocation by more than 50 miles, all as determined by Mr. Edwards in good faith. Termination for “cause” generally arises on willful failure to perform duties, commitment of a felony, gross neglect or willful misconduct resulting in material economic loss to National Grid USA or its subsidiaries, including the Company, or breach of certain confidentiality and non-compete provisions. “Cause” must be determined by a vote of three-fourths of National Grid USA’s Board of Directors after a meeting at which Mr. Edwards and his legal counsel are entitled to be heard.

Messrs. Ash, Nadeau and Tasker have change in control agreements with National Grid USA, which will remain in effect until January 31, 2004. If the officer terminates his employment for good reason or National Grid USA terminates the officer’s employment without cause, the officer will be entitled to a lump sum severance benefit equal to two times the officer’s base salary, plus two years of employee benefit plan coverage. “Good reason” and “cause” are defined in these agreements as they are in Mr. Edwards’s employment agreement.

Under the National Grid USA companies’ executive compensation plan, in the event of a change in control, each Named Executive Officer would receive a cash payment in an amount equal to the average annual bonus percentage for the incentive compensation plan level for the three prior years multiplied by that officer’s annualized base compensation. These payments would be made in lieu of the bonuses under these plans for the year in which the change in control occurs. In addition, provisions in the Retirees Health and Life Insurance Plan prevent changes in benefits adverse to the participants for three years following a change in control. Upon a change in control of National Grid USA, a participant in the deferred compensation plan may elect to receive a full distribution from the participant’s accounts plus the actuarial value of future benefits in relation to the insurance-related benefits under a prior plan, all less 10 percent.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table indicates the number of ordinary shares of National Grid Transco beneficially owned as of June 19, 2003 by: (a) each director of the Company; (b) each of the Named Executive Officers; and (c) all directors and executive officers of the Company as a group. Except as indicated, each such person has sole investment and voting power with respect to the shares shown as being beneficially owned by such person, based on information provided to the Company. Each person listed in this table owns less than one percent of the outstanding equity securities of National Grid Transco. Niagara Mohawk Holdings, Inc. owns all of the common stock of the Company.

Name	Number of Shares Beneficially Owned*
William F. Edwards	24,000
Clement E. Nadeau	24,300
Kwong O. Nuey, Jr.	16,445
Anthony C. Pini	16,705
Steven W.Tasker	12,820
Joseph T. Ash, Jr.	17,845
Michael E. Jesanis	34,925
All directors and officers as a group (11 persons)	229,840

*	This number is expressed in terms of ordinary shares. It includes American Depositary Receipts listed on the New York Stock Exchange, each of which represents five ordinary shares.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. CONTROLS AND PROCEDURES

The Company has established and maintains disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to the Company, including its consolidated subsidiaries, is made known to management by others within those entities, particularly during the period in which this annual report is being prepared. The Company has established a Disclosure Committee, which is made up of several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer. The Disclosure Committee monitors and evaluates these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report. Based on this evaluation, it was determined that these disclosure controls and procedures were effective in providing reasonable assurance during the period covered in this annual report. There were no significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Certain documents filed as part of the Form 10-K

(1) INDEX OF FINANCIAL STATEMENTS

Report of Independent Auditors

Niagara Mohawk Power Corporation Consolidated Statements of Operations, Consolidated Statements of Retained Earnings, and Consolidated Statements of Comprehensive Income (Loss) for the year ended March 31, 2003, the 60 day period ended March 31, 2002, the 30 day period ended January 30, 2002, and for the years ended December 31, 2001 and 2000.

Niagara Mohawk Power Corporation Consolidated Balance Sheets at March 31, 2003 and 2002

Niagara Mohawk Power Corporation Consolidated Statements of Cash Flows for the year ended March 31, 2003, the 60 day period ended March 31, 2002, the 30 day period ended January 30, 2002, and for the years ended December 31, 2001 and 2000

Notes to Consolidated Financial Statements

(2) The following financial statement schedule of the Company for the year ended March 31, 2003, the quarter ended March 31, 2002, and the years ended December 31, 2001 and 2000 are included:

Report of Independent Auditors on Financial Statement Schedule

Consolidated Financial Statement Schedule:

II--Valuation and Qualifying Accounts and Reserves -Niagara Mohawk

The Financial Statement Schedule above should be read in conjunction with the Consolidated Financial Statements in Part II, Item 8 (Financial Statements and Supplementary Data).

Schedules other than those mentioned above are omitted because the conditions requiring their filing do not exist or because the required information is given in the financial statements, including the notes thereto.

(3) List of Exhibits:

See Exhibit Index.

(b) Reports on Form 8-K

The Company did not file any Current Reports on Form 8-K during the last quarter of the fiscal year ended March 31, 2003.

On April 14, 2003, the Company filed a Current Report on Form 8-K containing Item 5.

REPORT OF INDEPENDENT AUDITORS
ON FINANCIAL STATEMENT SCHEDULE

To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:

Our audits of the consolidated financial statements of Niagara Mohawk Power Corporation referred to in our report dated May 7, 2003, appearing in this Form 10-K also included an audit of the Financial Statement Schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Boston, Massachusetts
May 7, 2003

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

(In thousands of dollars)

Column A	Column B	Column C	Column D	Column E
		Additions
	Balance at	Charged to		Balance
	Beginning	Costs and	Deductions	at End
Description	of Period	Expenses	(a)	of Period

Allowance for Doubtful
Accounts -Deducted from
Accounts Receivable in
the Consolidated
Balance Sheets

Year ended March 31, 2003	$ 61,301	$ 92,841	$ 53,919	$ 100,223
60 Days Ended March 31, 2002	57,498	10,503	6,700	61,301
30 Days Ended January 30, 2002	56,008	6,644	5,154	57,498
Year ended December 31, 2001	59,085	64,324	67,401	56,008
Year ended December 31, 2000	59,421	56,642	56,978	59,085

(a) Uncollectible accounts written off net of recoveries.

(In thousands of dollars)

Column A	Column B	Column C		Column D		Column E
		Additions
	Balance at	Charged to				Balance
	Beginning	Costs and				at End
Description	of Period	Expenses		Deductions		of Period (c)

Miscellaneous
Valuation Reserves (b)

Year Ended March 31, 2003	$ 9,435	$ -		$ -		$ 9,435
60 days ended March 31, 2002	9,435		-	-		9,435
30 days ended January 30, 2002	9,435	-		-		9,435
Year Ended December 31, 2001	32,380	194		23,139	(c)	9,435
Year Ended December 31, 2000	31,680	700		-		32,380

(b) The reserve in 2001 and after relates to non-rate base properties. In 1999 and 2000, the reserves related to certain materials and supplies inventory, non-rate base properties and a write-down against an investment.

(c) In 2001, Niagara Mohawk eliminated certain valuation reserves, including certain materials and supplies inventory reserve as a result of the sale of its nuclear assets in November 2001.

SIGNATURES

Pursuant to the Requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company.

	NIAGARA MOHAWK POWER
	CORPORATION


	By: /s/ William F. Edwards
	William F. Edwards
	President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on June 30, 2003 by the following persons on behalf of the registrant in the capacities indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company.

Signature	Title


/s/ William F. Edwards William F. Edwards	President, Chief Executive Officer and Director (Principal Executive Officer)


/s/ John G. Cochrane John G. Cochrane	Chief Financial Officer (Principal Financial Officer)


/s/ Edward A. Capomacchio Edward A. Capomacchio	Controller (Principal Accounting Officer)


/s/ Michael E. Jesanis Michael E. Jesanis	Director


/s/ Clement E. Nadeau Clement E. Nadeau	Director


/s/ Kwong O. Nuey Jr. Kwong O. Nuey	Director


/s/ Anthony C. Pini Anthony C. Pini	Director

CERTIFICATIONS

Certification of Principal Executive Officer

I, William F. Edwards, certify that:

1. I have reviewed this annual report on Form 10-K of Niagara Mohawk Power Corporation (the “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Report (the “Evaluation Date”); and

c) presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this Report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: June 30, 2003	/s/ William F. Edwards
	William F. Edwards
	President and Chief Executive Officer

Certification of Principal Financial Officer

I, John G. Cochrane, certify that:

1. I have reviewed this annual report on Form 10-K of Niagara Mohawk Power Corporation (the “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Report (the “Evaluation Date”); and

Date: June 30, 2003	/s/ John G. Cochrane
	John G. Cochrane
	Chief Financial Officer

NIAGARA MOHAWK POWER CORPORATION

EXHIBIT INDEX

Each document referred to in this Exhibit Index is incorporated by reference to the files of the Securities and Exchange Commission, unless designated with an asterisk. The cross-reference table below sets forth the registration statements and reports from which the exhibits are incorporated by reference.

Reference	Name

A	Niagara Mohawk Registration Statement No. 2-8214
B	Niagara Mohawk Registration Statement No. 2-8634
C	Central New York Power and Light Corporation Registration Statement No. 2-3414
D	Central New York Power and Light Corporation Registration Statement No. 2-5490
E	Niagara Mohawk Registration Statement No. 2-10501
F	Niagara Mohawk Registration Statement No. 2-12443
G	Niagara Mohawk Registration Statement No. 2-16193
H	Niagara Mohawk Registration Statement No. 2-26918
I	Niagara Mohawk Registration Statement No. 2-59500
J	Niagara Mohawk Registration Statement No. 2-70860
K	Niagara Mohawk Registration Statement No. 33-38093
L	Niagara Mohawk Registration Statement No. 33-47241
M	Niagara Mohawk Registration Statement No. 33-59594
N	Niagara Mohawk Registration Statement No. 33-49541
O	Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1994
P	Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1997
Q	Niagara Mohawk Annual Report on Form 10-K for year ended December 31, 1999
R	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended March 31, 1993
S	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended September 30, 1993
T	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended June 30, 1995
U	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended March 31, 1998
V	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended June 30, 1998
W	Niagara Mohawk Quarterly Report of Form 10-Q for quarter ended March 31, 1999
X	Niagara Mohawk Quarterly Report on Form 10-Q for quarter ended September 30, 2001
Y	Niagara Mohawk Current Report on Form 8-K dated July 9, 1997
Z	Niagara Mohawk Current Report on Form 8-K dated October 10, 1997
AA	Niagara Mohawk Current Report on Form 8-K dated November 30, 1999
BB	Niagara Mohawk Current Report on Form 8-K dated May 9, 2000
CC	Niagara Mohawk Current Report on Form 8-K dated September 25, 2001

In accordance with Paragraph 4(iii) of Item 601 (b) of Regulation S-K, the Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of the agreements comprising the $804 million senior bank financing that the Company completed with a bank group on June 1, 2000, and subsequently amended. The total amount of long-term debt authorized under such agreement does not exceed ten percent of the total consolidated assets of the Company and its subsidiaries.

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(a)(1)

Certificate of Consolidation of New York Power and Light Corporation, Buffalo Niagara Electric Corporation and Central New York Power Corporation, filed in the office of the New York Secretary of State, January 5, 1950

3(a)(2)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk, filed in the office of the New York Secretary of State, January 5, 1950

3(a)(3)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk pursuant to Section 36 of the Stock Corporation Law of New York, filed August 22, 1952, in the office of the New York Secretary of State

3(a)(4)

Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York filed May 5, 1954 in the office of the New York Secretary of State

3(a)(5)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk pursuant to Section 36 of the Stock Corporation Law of New York, filed January 9, 1957 in the office of the New York Secretary of State

3(a)(6)

Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York, filed May 22, 1957 in the office of the New York Secretary of State

3(a)(7)

Certificate of Niagara Mohawk pursuant to Section 11 of the Stock Corporation Law of New York, filed February 18, 1958 in the office of the New York Secretary of State

3(a)(8)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 5, 1965 in the office of the New York Secretary of State

3(a)(9)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 24, 1967 in the office of the New York Secretary of State

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(a)(10)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 19, 1968 in the office of the New York Secretary of State

3(a)(11)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 22, 1969 in the office of the New York Secretary of State

3(a)(12)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 12, 1971 in the office of the New York Secretary of State

3(a)(13)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 18, 1972 in the office of the New York Secretary of State

3(a)(14)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 26, 1973 in the office of the New York Secretary of State

3(a)(15)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 9, 1974 in the office of the New York Secretary of State

3(a)(16)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 12, 1975 in the office of the New York Secretary of State

3(a)(17)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 7, 1975 in the office of the New York Secretary of State

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(a)(18)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 27, 1975 in the office of the New York Secretary of State

3(a)(19)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 7, 1976 in the office of the New York Secretary of State

3(a)(20)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 28, 1976 in the office of the New York Secretary of State

3(a)(21)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed January 27, 1978 in the office of the New York Secretary of State

3(a)(22)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 8, 1978 in the office of the New York Secretary of State

3(a)(23)

Certificate of Correction of the Certificate of Amendment filed May 7, 1976 of the Certificate of Incorporation under Section 105 of the Business Corporation Law of New York, filed July 13, 1978 in the office of the New York Secretary of State

3(a)(24)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed July 17, 1978 in the office of the New York Secretary of State

3(a)(25)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 3, 1980 in the office of the New York Secretary of State

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(a)(26)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 31, 1981 in the office of the New York Secretary of State

3(a)(27)

3(a)(28)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 22, 1981 in the office of the New York Secretary of State

3(a)(29)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 8, 1981 in the office of the New York Secretary of State

3(a)(30)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 26, 1982 in the office of the New York Secretary of State

3(a)(31)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed January 24, 1983 in the office of the New York Secretary of State

3(a)(32)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 3, 1983 in the office of the New York Secretary of State

3(a)(33)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 27, 1983 in the office of the New York Secretary of State

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(a)(34)

3(a)(35)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 4, 1984 in the office of the New York Secretary of State

3(a)(36)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 29, 1984 in the office of the New York Secretary of State

3(a)(37)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed April 17, 1985 in the office of the New York Secretary of State

3(a)(38)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 3, 1985 in the office of the New York Secretary of State

3(a)(39)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed December 24, 1986 in the office of the New York Secretary of State

3(a)(40)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 1, 1987 in the office of the New York Secretary of State

3(a)(41)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed July 20, 1987 in the office of the New York Secretary of State

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(a)(42)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 27, 1988 in the office of the New York Secretary of State

3(a)(43)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed September 27, 1990 in the office of the New York Secretary of State

3(a)(44)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed October 18, 1991 in the office of the New York Secretary of State

3(a)(45)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed May 5, 1994 in the office of the New York Secretary of State

3(a)(46)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed August 5, 1994 in the office of the New York Secretary of State

3(a)(47)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed June 29, 1998 in the office of the New York Secretary of State

3(a)(48)

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed March 19, 1999 in the office of the New York Secretary of State

3(a)(49)

3.1

Certificate of Amendment of Certificate of Incorporation of Niagara Mohawk under Section 805 of the Business Corporation Law of New York, filed November 29, 1999 in the office of the New York Secretary of State

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

3(b)

3(i)

By-Laws of Niagara Mohawk, as amended May 17, 1999

4(a)

4(b)

Agreement to furnish certain debt instruments

4(b)(1)

Mortgage Trust Indenture dated as of October 1, 1937 between Niagara Mohawk (formerly CNYP) and Marine Midland Bank, N.A. (formerly named The Marine Midland Trust Company of New York), as Trustee

4(b)(2)

2-3

Supplemental Indenture dated as of December 1, 1938, supplemental to Exhibit 4(1)

4(b)(3)

2-4

Supplemental Indenture dated as of April 15, 1939, supplemental to Exhibit 4(1)

4(b)(4)

2-5

Supplemental Indenture dated as of July 1, 1940, supplemental to Exhibit 4(1)

4(b)(5)

7-6

Supplemental Indenture dated as of October 1, 1944, supplemental to Exhibit 4(1)

4(b)(6)

2-8

Supplemental Indenture dated as of June 1, 1945, supplemental to Exhibit 4(1)

4(b)(7)

2-9

Supplemental Indenture dated as of August 17, 1948, supplemental to Exhibit 4(1)

4(b)(8)

7-9

Supplemental Indenture dated as of December 31, 1949, supplemental to Exhibit 4(1)

4(b)(9)

7-10

Supplemental Indenture dated as of January 1, 1950, supplemental to Exhibit 4(1)

4(b)(10)

7-11

Supplemental Indenture dated as of October 1, 1950, supplemental to Exhibit 4(1)

** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414.

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

4(b)(11)

7-12

Supplemental Indenture dated as of October 19, 1950, supplemental to Exhibit 4(1)

4(b)(12)

4-16

Supplemental Indenture dated as of February 20, 1953, supplemental to Exhibit 4(1)

4(b)(13)

4-19

Supplemental Indenture dated as of April 25, 1956, supplemental to Exhibit 4(1)

4(b)(14)

2-23

Supplemental Indenture dated as of March 15, 1960, supplemental to Exhibit 4(1)

4(b)(15)

4-29

Supplemental Indenture dated as of July 15, 1967, supplemental to Exhibit 4(1)

4(b)(16)

4(b)(42)

Supplemental Indenture dated as of March 1, 1978, supplemental to Exhibit 4(1)

4(b)(17)

4(b)(46)

Supplemental Indenture dated as of June 15, 1980, supplemental to Exhibit 4(1)

4(b)(18)

4(b)(75)

Supplemental Indenture dated as of November 1, 1990, supplemental to Exhibit 4(1)

4(b)(19)

4(b)(77)

Supplemental Indenture dated as of October 1, 1991, supplemental to Exhibit 4(1)

4(b)(20)

4(b)(79)

Supplemental Indenture dated as of June 1, 1992, supplemental to Exhibit 4(1)

4(b)(21)

4(b)(81)

Supplemental Indenture dated as of August 1, 1992, supplemental to Exhibit 4(1)

4(b)(22)

4(b)(82)

Supplemental Indenture dated as of April 1, 1993, supplemental to Exhibit 4(1)

4(b)(23)

4(b)(83)

Supplemental Indenture dated as of July 1, 1993, supplemental to Exhibit 4(1)

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

4(b)(24)

4(86)

Supplemental Indenture dated as of July 1, 1994, supplemental to Exhibit 4(1)

4(b)(25)

4(87)

Supplemental Indenture dated as of May 1, 1995, supplemental to Exhibit 4(1)

4(b)(26)

4(a)(39)

Supplemental Indenture dated as of March 20, 1996, supplemental to Exhibit 4(1)

4(b)(27)

4(b)40

Supplemental Indenture dated as of November 1, 1998, supplemental to Exhibit 4(1)

4(b)(28)

7-23

Agreement dated as of August 16, 1940, among CNYP, The Chase National Bank of the City of New York, as Successor Trustee, and The Marine Midland Trust Company of New York, as Trustee

4(c)

4(a)(41)

Form of Indenture relating to the Senior Notes dated June 30, 1998

4(d)(1)

1.2

Indenture, dated as of May 12, 2000, between Niagara Mohawk Power Corporation, a New York Corporation, and The Bank of New York, a New York banking corporation, as Trustee

4(d)(2)

1.3

First Supplemental Indenture, dated as of May 12, 2000, between Niagara Mohawk Power Corporation, a New York corporation, and The Bank of New York, a New York banking corporation, as Trustee

4(d)(3)

1.2

Form of Second Supplemental Indenture, between Niagara Mohawk Power Corporation and The Bank of New York, as Trustee

4(e)(1)

Supplemental Indenture, dated as of May 1, 2003, between Niagara Mohawk Power Corporation and HSBC Bank USA, as Trustee

4(e)(2)

First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $100,000,000 Pollution Control Revenue Bonds, 1985 Series A

4(e)(3)

First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $37,500,000 Pollution Control Revenue Bonds, 1985 Series B

4(e)(4)

First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $37,500,000 Pollution Control Revenue Bonds, 1985 Series C

4(e)(5)

First Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $50,000,000 Pollution Control Revenue Bonds, 1986 Series A

4(e)(6)

Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $25,760,000 Pollution Control Revenue Bonds, 1987 Series A

4(e)(7)

Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $93,200,000 Pollution Control Revenue Bonds, 1987 Series B

4(e)(8)

Second Supplemental Participation Agreement, dated as of May 1, 2003, between New York State Energy Research and Development Authority and Niagara Mohawk Power Corporation relating to $69,800,000 Pollution Control Revenue Bonds, 1988 Series A

10(a)

10.28

Master Restructuring Agreement dated July 9, 1997 among Niagara Mohawk and the 16 independent power producers signatory thereto

10(b)

99-9

Power Choice settlement filed with the PSC on October 10, 1997

	INCORPORATION BY REFERENCE

EXHIBIT NO.	PREVIOUS FILING	PREVIOUS EXHIBIT DESIGNATION	DESCRIPTION

10(c)

10-13

PSC Opinion and Order regarding approval of the Power Choice settlement agreement with PSC, issued and effective March 20, 1998

10(d)

10(c)

Amendments to the Master Restructuring Agreement

10(e)

10-14

Independent System Operator Agreement dated December 2, 1999

10(f)

10-15

Agreement between New York Independent System Operator and Transmission Owners dated December 2, 1999

10(g)

10-9

PSC Opinion and Order regarding approval of the sale of Nine Mile Point Nuclear Station Units No. 1 and No. 2

10(h)

10-10

Merger Rate Agreement reached among Niagara Mohawk, the PSC staff and other parties, filed with the PSC on October 11, 2001

Subsidiaries of the Registrant

99.1

Certification of CEO under Section 906 of the Sarbanes-Oxley Act of 2002

99.2

Certification of CFO under Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith.

NIAGARA MOHAWK POWER CORP /NY/ 10-K